UPL
Annual Report 2018

Plain-text annual report

Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549Form 10-K ☑☑ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2018 ☐☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from toCommission file number 001-33614ULTRA PETROLEUM CORP.(Exact name of registrant as specified in its charter) Yukon, Canada N/A(State or other jurisdiction ofincorporation or organization) (I.R.S. employeridentification number) 116 Inverness Drive East, Suite 400Englewood, Colorado 80112(Address of principal executive offices) (Zip code)(303) 708-9740(Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Exchange on Which RegisteredCommon Shares, without par value NASDAQ Global Select MarketSecurities 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 preceding12 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 (Section232.405) 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 (Section 229.405) is not contained herein, and will not be contained, to the best ofregistrant’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, smaller reporting company, or an emerging growth company. Seethe definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer☐ Accelerated filer☑Non-accelerated filer☐ Smaller reporting company ☐Emerging Growth company☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐ NO ☑The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $369,920,487 as of June 29, 2018 (based on the last reportedsales price of $2.31 of such stock on the NASDAQ Global Select Market on such date).Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent tothe distribution of securities under a plan confirmed by a court. YES ☑ NO ☐The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of February 28, 2019 was 197,383,295.Documents incorporated by reference:Portions of the registrant’s definitive proxy statement relating to its 2018 and 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commissionwithin 120 days after December 31, 2018, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Form 10-K. Table of Contents TABLE OF CONTENTS Page PART I Item 1. Business 3 Item 1A. Risk Factors 13 Item 1B. Unresolved Staff Comments 27 Item 2. Properties 27 Item 3. Legal Proceedings 33 Item 4. Mine Safety Disclosures 33 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 34 Item 6. Selected Financial Data 36 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 37 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 54 Item 8. Financial Statements and Supplementary Data 56 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures 94 Item 9A. Controls and Procedures 94 Item 9B. Other Information 94 PART III Item 10. Directors, Executive Officers and Corporate Governance 95 Item 11. Executive Compensation 95 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 95 Item 13. Certain Relationships, Related Transactions and Director Independence 95 Item 14. Principal Accounting Fees and Services 95 PART IV Item 15. Exhibits, Financial Statement Schedules 96 Signatures 100 Certain Definitions 101 Table of Contents PART IItem 1.Business.GeneralUltra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, or “us”) is an independent oil and gascompany engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company was incorporatedin 1979, under the laws of the Province of British Columbia, Canada. Ultra remains a Canadian company, and since March 2000, has operated under the lawsof Yukon, Canada pursuant to Section 190 of the Yukon Business Corporations Act. The Company’s principal business activities are developing andproducing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of southwest Wyoming.The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to suchreports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free ofcharge to the public on the Company’s website at www.ultrapetroleum.com as soon as reasonably practicable after such material is electronically filed with,or furnished to, the SEC. You may also request a copy of these filings at no cost by making written or telephone requests for copies to Ultra Petroleum Corp.,Investor Relations, 116 Inverness Drive East, Suite 400, Englewood, CO 80112, (303) 708-9740, ext. 9898. The SEC maintains an internet site that containsreports, proxy and information statements, and other information regarding the Company. The SEC’s website address is www.sec.gov.Oil and Gas Properties OverviewPrincipal Operating AreaUltra’s operations in southwest Wyoming have historically focused on developing its long-life natural gas reserves in a tight gas sand trend located inthe Green River Basin. The Company targets sands of the upper Cretaceous Lance Pool in the Pinedale and Jonah fields. The Lance Pool, as administered bythe Wyoming Oil and Gas Conservation Commission (“WOGCC”), includes sands of the Lance formation at depths between approximately 8,000 and12,000 feet and the Mesaverde formation at depths between approximately 12,000 and 14,000 feet. As of December 31, 2018, Ultra owned interests inapproximately 114,000 gross (79,000 net) acres in Wyoming covering approximately 190 square miles. Following the sale of the Company’s Pennsylvaniaproperties in late 2017 and Utah assets in late 2018, all oil and gas operations are now focused in the Pinedale and Jonah fields.2018 and 2017 DivestituresThe Company previously had operations in the Uinta Basin in Utah and in north central Pennsylvania.On September 25, 2018, the Company completed the sale of its Utah assets for net cash proceeds of $69.3 million, including management fees of $0.6million. The divested assets consisted primarily of oil and gas properties. Prior to the sale, production from the Company’s Utah assets totaled approximately420,000 Bbl of oil and 745,000 Mcf of natural gas in 2018.During the fourth quarter of 2017, the Company divested its properties in the Pennsylvania Devonian aged Marcellus Shale, for net cash proceeds ofapproximately $115.0 million. Prior to the sale, production from the Pennsylvania assets totaled approximately 11.2 million Mcf of natural gas in 2017.Mission and StrategyUltra’s mission is to profitably grow as an upstream oil and gas company for the long-term benefit of its shareholders. Ultra’s strategy to achieve thisgoal includes managing its portfolio of assets in Wyoming, maintaining a disciplined approach to capital investment, maximizing earnings and cash flows bycontrolling costs, utilizing advancements in drilling technologies to maximize results, and improving its financial flexibility.High Return Portfolio. Ultra seeks to maintain a portfolio of properties that provide long-term, profitable growth through development in areas thatsupport sustainable, lower-risk, repeatable, high-return drilling projects. The Company evaluates opportunities for the acquisition, exploration, anddevelopment of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.Disciplined Capital Investment. The Company’s business strategy includes proactive and regular review of its portfolio of investment opportunitieswith a focus on investments that produce positive returns in order to optimize return to its shareholders. The Company seeks to develop the resource fromexisting assets, while spending within cash flows in order to maximize profitability. Focus on Maximizing Value. Ultra strives to maintain one of the lowest cost structures in the industry in terms of both adding and producing oil andnatural gas reserves. The Company continues to focus on improving its drilling and production results using advanced technologies and detailed technicalanalysis of its properties, while maintaining its low-cost structure, adhering to industry and regulatory best practices, maintaining strict safety andenvironmental standards, and recruiting and retaining top talent within the Company. 3Table of Contents Financial Liquidity. Improving financial flexibility and strengthening the balance sheet are also key components of Ultra’s business philosophy. AtDecember 31, 2018, the Company had cash on hand of $17.0 million and outstanding debt of $2.2 billion. At December 31, 2018, the Company hadborrowing base capacity of $325.0 million under its revolving credit facility (the “Revolving Credit Facility”) pursuant to the borrowing baseredetermination, of which $104.0 million was outstanding. Further, the Company seeks to improve its cash flow visibility by hedging a portion of itsforecasted volumes on an annual basis in order to manage commodity price risks and provide cash flow predictability.Subsequent to December 31, 2018, the Company reaffirmed its borrowing base at $1.3 billion, providing for $325.0 million of availability, and alsoentered into a Fourth Amendment to the Revolving Credit Facility providing expansion of its allowed leverage metric, as well as other enhancements to theutility of the facility. The next borrowing base redetermination is scheduled for the fall of 2019. This proactive effort is one of several steps towards buildingin time to execute the Company’s business plan and leverages the benefit from the December 2018 Exchange Transaction described below. In December 2018, the Company exchanged (i) $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022Notes”) and (ii) $275 million aggregate principal amount, or 55%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of the Company for (a) $545.0million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “Second LienNotes”) and (b) an aggregate of 10,919,499 new warrants of the Company entitling the holder thereof to purchase one common share of the Company (each a“Warrant” and collectively, the “Warrants”) (such transaction, the “Exchange Transaction”). The Exchange Transaction reduced principal balance of theindebtedness by $235 million. Following the Exchange Transaction, the average debt maturity was extended to 5.1 years. The weighted average cost of debtprior to the Exchange Transaction was approximately 6.3% and increased to approximately 8% after the exchange.See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” for adescription of the Revolving Credit Facility and additional details regarding the Exchange Transaction.Following the Exchange Transaction, subsequent to December 31, 2018, and through the date of this filing, the Company has successfully exchangedan additional $44.6 million aggregate principal amount of 2022 Notes for $27.0 million aggregate principal amount of Second Lien Notes, reducingindebtedness by $252.5 million (inclusive of the Exchange Transaction). Under the indenture governing the Second Lien Notes, the Company was permittedto exchange up to approximately $55.0 million of 2022 Notes for Second Lien Notes at terms that are the same or more favorable to the Company than theterms of the Exchange Transaction. The Company continues to retain the ability under the indenture to further exchange approximately $10.4 million of theremaining 2022 Notes within one year of the Exchange Transaction. Exploration and ProductionSee Item 2. “Properties” for a description of our properties.Green River Basin, WyomingDuring 2018, the Company participated in the drilling and casing of 116 vertical and 19 horizontal wells operated by the Company and others inWyoming and continued its drilling and completion efficiency on its operated wells. In line with the Company’s commitment to make its operations moreefficient, the Company’s operated well costs for vertical wells declined from an annual average of $3.8 million per well during 2014 to an annual average of$3.2 million per well during 2018, and $3.1 million in the fourth quarter of 2018 as the Company restored its primary vertical well development program.The reduction in costs is attributable to drilling efficiencies, such as pad drilling and simultaneous operations for drilling and completion activities,application of technology and service cost reductions. The Company operates 89% of its production in the Pinedale field. The horizontal well program in2018 resulted in several successful wells; however, the majority of the horizontal program was marginally economic to uneconomic, causing the Company tosuspend this program in the third quarter of 2018 in order to evaluate the results, including the application of advanced geologic and engineering analysisand detailed evaluation of the horizontal wells that had been developed. Ultra has completed one additional horizontal well in early 2019 and will integratethe results from this well into its analysis on developing the horizontal program.During 2019, the Company plans, based on the availability of capital, to continue developing its position in the Pinedale field, and will continue totarget tight gas sands of the Lance Pool, predominately through the development of vertical wells. All of the Company’s drilling activity is conductedutilizing historical well performance, completion efficiency, and its extensive geological and geophysical data set. This data set is used to map theproductive intervals, to refine areas of drilling focus, to identify areas for future extension of the Lance fairway with both vertical and horizontal wells, as wellas to consider other deeper horizons that may be viable development candidates.UtahDuring 2018, the Company did not drill any wells on the Uinta Basin properties, The Company sold all of its Utah oil and gas properties in September2018.4Table of Contents Marketing and PricingOverviewDuring the year ended December 31, 2018, Ultra derived its revenues from the sale of its natural gas and associated condensate produced from wellsoperated by the Company in the Green River Basin in southwest Wyoming, and from the sale of crude oil and natural gas from wells operated by theCompany in the Uinta Basin in Utah. In September 2018, the Company divested its properties on the Uinta Basin in Utah.During 2018, 95% of the Company’s production and 81% of its revenues were attributable to natural gas, with the balance attributable to associatedcondensate and crude oil. In the fourth quarter of 2018, subsequent to the sale of its Utah assets, 96% of Ultra’s production and 89% of its revenue were fromthe sale of natural gas.The Company’s natural gas and oil revenues are determined by prevailing market prices in the Rocky Mountain region of the United States,specifically, southwest Wyoming as virtually all of its natural gas sold at the Inside FERC First of Month Index for Northwest Pipeline — Rocky Mountains(“NwRox”) is the price that is reflective of the Company’s gas sold in the Opal, Wyoming area. The NwRox and New York Mercantile Exchange (“NYMEX”)is the price that is reflective of the Company’s gas sold in the Opal, Wyoming area.The NwRox can be volatile from time to time, particularly in peak winter and summer periods, as evidenced in November and December 2018 whennatural gas at that delivery point was selling for $0.05 and $0.98, respectively, per MMBtu above NYMEX pricing for natural gas. We also use derivativeinstruments in the management of the cash flows of our business, as discussed below.Natural Gas MarketingUltra currently sells all its natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of variousdurations and prices (daily, monthly and longer term). The Company’s customer base includes a significant number of customers situated in the variousregions of the United States. The sale of the Company’s natural gas is “as produced”.Midstream services. For its natural gas production in Wyoming, the Company has entered into various gathering and processing agreements withmidstream service providers that gather, compress and process natural gas owned or controlled by the Company from its producing wells in the PinedaleAnticline and Jonah fields. Under these agreements, the midstream service providers continue to maintain and upgrade their facilities in southwest Wyomingto ensure reliability and certainty of operations. The Company believes that the capacity of the midstream infrastructure related to its production willcontinue to be adequate to allow it to sell all its available natural gas production.Basis differentials. The market price for natural gas is influenced by a number of regional and national factors which are beyond the Company’sability to control. These factors include, among others, weather in the western United States, natural gas supplies, imports from Canada, natural gas demand,inventory levels in natural gas storage fields, and natural gas pipeline capacity to export gas from the basins where the Company’s production is located. SeeItem 1A. “Risk Factors” for more information about risks to our financial condition and business results associated with basis differentials.The Rocky Mountain region is a net exporter of natural gas because local natural gas production exceeds local demand, especially during non-wintermonths. As a result, natural gas production in southwest Wyoming has from time to time sold at a discount relative to other U.S. natural gas productionsources or market areas. These regional pricing differentials, or discounts, are typically referred to as “basis” or “basis differentials” and are reflective, to someextent, of (i) the costs associated with transporting the Company’s gas to markets in other regions or states, and (ii) the availability of pipeline capacity tomove the Company’s gas to market.Since the completion of the Rockies Express and Ruby pipelines, the average annual basis for NwRox averaged 5.6% below Henry Hub from 2012through 2016. The additional capacity of these two pipelines has had a significant positive impact on the value that the Company receives for its natural gasproduction in southwest Wyoming, as compared to prior years when constraints were prevalent in the region. However, during 2017 and 2018, NwRox basishas weakened from levels realized in 2012 through 2016 mainly due to weakening fundamentals in the Company’s core delivery area, California, andincreasing flows from regions that produce significant quantities of oil and are connected by gas pipelines to the California market. In 2017 and 2018,NwRox basis averaged an 11.5% and 14.4%, respectively, discount to Henry Hub. This expansion in the percentage differential is due to lower absolutenatural gas prices as well as significant competition for markets due to robust natural gas production in constrained areas such as the Permian and DelawareBasins in Texas, the Marcellus Shale in Pennsylvania and the Utica Shale in Ohio. The average basis differential of NwRox was $0.36 and $0.44 below theHenry Hub in 2017 and 2018, respectively.While trades indicate that the basis differentials for the forward-looking basis market for 2019 and 2020 are negative to Henry Hub by approximately$0.30 and $0.46, respectively, there is expected improvement in NwRox basis beginning in 2020 as pipeline expansions and processing capacity in thePermian and Delaware Basins increase as well as processing and export capacity from the Houston and Beaumont areas. The increased take-away capacity inthese regions may improve the NwRox basis as competition for gas flowing into the mid-continent region and the West Coast are redirected to more localmarkets.5Table of Contents The table below provides a historical perspective on average quarterly basis differentials for Wyoming natural gas (NwRox). The basis differential isexpressed as a percentage of the Henry Hub price as reported by Platt’s M2M (Mark to Market) Report and Bloomberg on December 31, 2018 and 2017. 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter NwRox 83% 70% 80% 103%NYMEX $3.00 $2.80 $2.90 $3.64 2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter NwRox 92% 84% 87% 89%NYMEX $3.32 $3.18 $3.00 $2.93 Oil MarketingWyoming. The Company markets its Wyoming condensate to various purchasers, which are primarily refiners in the Salt Lake City, Utah area. TheCompany’s condensate realized pricing is typically based on New York Mercantile Exchange crude futures daily settlement prices, adjusted for a negotiatedlocation/transportation differential. All of the Company’s condensate sales are denominated in U.S. dollars per barrel and are paid monthly. The Companyroutinely maintains only operating inventories of condensate production and sells its product on an “as produced” basis. A portion of the Company’scondensate sales are entered into by its operating partners in the Pinedale field. Over 94% of oil is transported via pipeline, thereby greatly reducing the riskof spills and losses. During 2018, the Company realized a positive differential of $1.84, excluding anomalies for pipeline outages, to a West TexasIntermediate price. The improvement in the differential was a result of strong refining demand for the quality of condensate produced in the Pinedale area.This trend of strengthening oil differentials is expected to continue in 2019, as evidence by the contracts in place through 2019 at a positive differential of$3.23 per Bbl.Utah. Prior to the Company’s sale of its Uinta Basin properties in September 2018, such properties produced what is typically referred to as BlackWax Crude, considered a medium grade of crude oil. This oil was marketed through short-term or long-term contracts with refiners in the Salt Lake City, Utaharea. The price for the Company’s crude oil production was typically based off of NYMEX pricing for West Texas Intermediate Crude Oil or from a postingfor Black Wax Crude in the Uinta Basin, less a negotiated location/transportation discount or differential.DerivativesThe Company, from time to time and in the regular course of its business, enters into hedges for volumes equivalent to a portion of expected futureproduction volumes, primarily through the use of financial swaps, collars and puts with creditworthy financial counterparties (See Note 8), or through the useof fixed price, forward sales of physical product. The Company’s Revolving Credit Facility requires the Company to hedge 65% of forecast proved producingnatural gas production, based on its most recent reserve report for 18 months from the end of the given quarter. This requirement is in effect throughSeptember 30, 2019. After that time, the requirement decreases to 50% of the estimated proved producing forecast for natural gas through March 31,2020. This means the Company may unwind hedges after September 30, 2019 at its discretion, provided the Company remains hedged at the 50% level fornatural gas. Additionally, the Revolving Credit Facility limits the amount of hedging to 85% of forecast production for all products within a givenquarter. The Company plans to enter into additional hedge positions in much the same manner as it has done previously. See Item 7A. “Quantitative andQualitative Disclosures About Market Risk”.The Company considers the requirements of the Revolving Credit Facility when developing its hedging policy. The Company’s management andboard of directors has a Hedge Committee that reviews the forecast production, the requirements under the Revolving Credit Facility, and the market outlookto determine the timing and the manner in which to hedge with the underlying goal to provide a level of cash flow predictivity while preserving someflexibility to participate in upward price movements.Significant CounterpartiesA significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2018, theCompany had no single counterparty that represented 10% or more of the Company’s total revenues.6Table of Contents The Company maintains credit policies intended to mitigate the risk of uncollectible accounts receivable related to the sale of natural gas andcondensate as well as commodity derivatives. A more complete description of the Company’s credit policies is described in Note 13. The Company takesmeasures to ensure collectability with its purchasers through regular credit monitoring and reviews. As necessary, the Company requires prepayment, lettersof credit or parental guarantees from its purchasers for the periods of exposure. The Company did not have any outstanding, uncollectible accounts for itsnatural gas and oil sales at December 31, 2018.Regulatory MattersThe Company’s oil and gas operations are subject to a number of regulations. Governing agencies may include one or more of the following levels:federal, regional, state, county, municipality, Tribal or other public entities. In general, the purposes of these regulations are to prevent waste of oil andnatural gas resources, protect the rights of surface and mineral owners, regulate interstate transportation of oil and gas, and to govern environmental quality.Common forms of regulations may include: •Notification to stakeholders of proposed and ongoing operations; •Nondiscrimination statutes; •Royalty and related valuation requirements; •On-site security and bonding requirements; •Location and density of drilling; •Method of drilling, completing and operating wells; •Measurement and reporting of oil and gas; •Rates, terms and conditions applicable to the interstate transportation of oil and gas; •Production, severance and ad valorem taxes; •Management of produced water and waste; and •Surface use, reclamation and plugging and abandonment of wells.A significant portion of the Company’s operations are located on federal lands in the Pinedale and Jonah Fields of Sublette County, Wyoming. Thedevelopment activities in these fields are subject to the regulation of the U.S. Bureau of Land Management (“BLM”) which is responsible for governing theirsurface and mineral rights and regulating certain development activities in these fields. As required under the National Environmental Policy Act (“NEPA”),an Environmental Impact Statement (“EIS”) was prepared to quantify and address potential impacts of natural gas development in both the Pinedale andJonah fields. In March 2006, the BLM issued its Record of Decision (“ROD”) which provides broad authorization for the development activities currentlyoccurring in the Jonah Area. In September 2008, the BLM issued its ROD that currently governs the development activities in the Pinedale Area. In additionto the overarching authorizations provided by the Jonah and Pinedale RODs, BLM issues site-specific authorizations such as rights of way and permits todrill on an ongoing basis.The Pinedale ROD includes some significant components to ensure the orderly and responsible development of natural gas concurrent to minimizingthe environmental impact. Some of these components include: •Year-round operations on multi-wells pads; •Liquid gathering systems to reduce truck traffic and minimize impacts to air quality and wildlife; •Monitoring of key wildlife species and mitigation of monitored impacts; •Advanced emission reductions including best practices such as controlled drill rigs; •Spatial progression of development to address specific surface and wildlife issues; •Annual meeting and long-range planning requirements to allow for socioeconomic predictability; •Adaptive Management to consider current and changing conditions and facilitate common-sense solutions; and •Suspension of flank acreage until core acreage is developed and returned to a functioning habitat.While the majority of the Company’s operations in Wyoming are covered by the Pinedale ROD, provisions of the Jonah ROD similarly ensureresponsible and orderly development of the Jonah field while minimizing the environmental impact: •Annual reporting and long-range planning requirements to allow for planned mitigation and socioeconomic predictability; •Emission reduction report to ensure air quality goals are met; •Annual water well monitoring reports; and •Flareless-completion technology to reduce noise, visual impacts and air emissions.7Table of Contents The State of Wyoming maintains governance over some of the more traditional state-regulated matters such as individual well drilling permits, spacingand pooling, wellbore construction, as well as its own regulations on safety and environmental matters. The Wyoming Oil and Gas Conservation Commission(“WOGCC”) has authorized drilling density up to one well per five acres in the Pinedale field and up to one well per ten acres in the Jonah field.Regulations are well documented and the Company believes that it is substantially in compliance with current applicable laws and regulations and thatcontinued compliance with existing requirements will not have a material adverse impact on the Company. However, changes to certain existing regulationsare beyond the control of the Company and could introduce uncertainty and additional costs. See Item1A “Risk Factors” for additional information regardingenvironmental regulations.In December 2018 and January 2019, a portion of the federal government shut down after Congress failed to pass a continuing resolution. This shut-down included all nonessential personnel at the BLM, including BLM staff tasked with processing drilling permits and sundries. The Company has adequateinventory of approved applications for permit to drill to implement our 2019 drilling schedule, but any changes or deviations from what is approved in thesepermits cannot be approved during a shut-down, should another one occur, thus creating a compliance risk. In addition, such government disruptions coulddelay or halt the granting and renewal of the permits, approvals, and certificates required to conduct our operations. The WOGCC continues to permit andoversee drilling operations.Mineral Leasing ActThe Mineral Leasing Act of 1920 (“Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and gas leases by a foreigncitizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. State or territory,and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of theUnited States. If these restrictions are violated, the oil and gas lease can be canceled in a proceeding instituted by the United States Attorney General. TheCompany’s subsidiaries that own mineral leases qualify as a corporation formed under the laws of the United States or of any U.S. State or territory. Althoughthe regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there arepresently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that holders of theCompany’s equity interests may be citizens of foreign countries that are determined to be non-reciprocal countries under the Mineral Act. In such event, thefederal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.Environmental and Occupational Safety and Health MattersSurface Damage ActsSeveral states, including Wyoming, and some tribal nations have enacted surface damage statutes. These laws are designed to compensate for damagescaused by oil and gas development operations. Most surface damage statutes contain entry and negotiation requirements to facilitate contact between theoperator and surface owners. Most also contain binding requirements for payments by the operator in connection with development operations. Costs anddelays associated with surface damage statutes could impair operational effectiveness and increase development costs.Environmental RegulationsGeneral. The Company’s exploration, drilling and production activities from wells and oil and natural gas facilities, including the operation andconstruction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to numerousstringent federal, state and local laws and regulations relating to environmental quality, including those relating to oil spills and pollution control. Theselaws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal andset environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance ofbonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use andrestoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters.The U.S. Environmental Protection Agency (“EPA”) has identified environmental compliance by the energy extraction sector as one of its enforcementinitiatives for fiscal years 2017-2019 and as a general matter, the oil and gas exploration and production industry has been and continues to be the subject ofincreasing scrutiny and regulation by environmental authorities.8Table of Contents Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and theimposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significantcosts and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. However, it isanticipated that, absent the occurrence of an extraordinary event, compliance with these laws and regulations will not have a material effect upon theCompany’s operations, capital expenditures, earnings or competitive position.Solid and Hazardous Waste. The Company has previously owned or leased and currently owns or leases, numerous properties that have been used forthe exploration and production of oil and natural gas for many years. Although the Company utilized standard operating and disposal practices,hydrocarbons or other solid wastes may have been disposed of or released on or under such properties or on or under locations where such wastes have beentaken for disposal. In addition, many of these properties are or have been operated by third parties over whom the Company has no control, nor has ever hadcontrol as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. Stateand federal laws applicable to oil and natural gas wastes and properties have gradually become stricter over time. Under current and evolving law, it ispossible the Company could be required to remediate property, including ground water, impacted by operations of the Company or by such third-partyoperators, or impacted by previously disposed wastes including performing remedial plugging operations to prevent future, or mitigate existingcontamination.Although oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”) under the federal Resource Conservationand Recovery Act (“RCRA”) and some comparable state statutes, it is possible some wastes the Company generates presently are or in the future may besubject to regulation under RCRA and state analogs, even as non-hazardous wastes. The EPA and various state agencies have limited the disposal options forcertain wastes, including Hazardous Wastes and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. Forexample, in May 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia that sought to compel the EPA toreview and, if necessary, revise its regulations regarding existing exemptions for exploration and production related wastes. Pursuant to a consent decreeentered December 28, 2016 that settled the lawsuit, the EPA committed to propose by March 15, 2019 new regulations for the management of oil and gaswastes under RCRA Subtitle D (which relates to non-hazardous wastes), or sign a determination that a revision of existing rules is unnecessary. If the EPAproposes new rulemaking, the Consent Decree requires the EPA to take final action on such rules no later than July 15, 2021. Furthermore, certain wastesgenerated by the Company’s oil and natural gas operations that are currently exempt from designation as Hazardous Wastes may in the future be designatedas Hazardous Wastes under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.In addition, current and future regulations governing the handling and disposal of Naturally Occurring Radioactive Materials (“NORM”) may affectour operations. For example, in Wyoming any waste material exceeding specified thresholds is subject to controls and guidance by the Wyoming Departmentof Environmental Quality Solid and Hazardous Waste Division, which determines how and where NORM wastes will be disposed of.Hydraulic Fracturing. Many of the Company’s exploration and production operations depend on the use of hydraulic fracturing to enhanceproduction from oil and gas wells. Hydraulic fracturing activities are typically regulated by state oil and gas commissions. The EPA has asserted federalregulatory authority over certain hydraulic-fracturing activities under the federal Safe Drinking Water Act (“SDWA”) involving the use of diesel fuels andpublished permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Congress has periodically considered legislation toamend the SDWA to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing (except where diesel is a componentof the fracturing fluid) and to require the disclosure and reporting of the chemicals used in hydraulic fracturing. This type of federal legislation, if adopted,could lead to additional regulation and permitting requirements that could result in operational delays making it more difficult to perform hydraulicfracturing and increasing our costs of compliance and operating costs.In addition, the EPA has issued guidance regarding federal regulatory authority over hydraulic fracturing using diesel under the Safe Drinking WaterAct’s Underground Injection Control Program. Further, in December 2016 the EPA released its final report on a wide-ranging study on the effects of hydraulicfracturing resources. While no widespread impacts from hydraulic fracturing were found, the EPA identified a number of activities and factors that may haveincreased risk for future impacts. Furthermore, a number of public and private studies are underway regarding the connection, if any, between the disposal ofwaste water associated with hydraulic fracturing and observed seismicity in the vicinity of such disposal operations. These studies and the EPA’s enforcementinitiative for the energy extraction sector could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing andincrease our costs of compliance and doing business.9Table of Contents In addition, some states, including Wyoming, have adopted, and other states are considering adopting, regulations that require disclosure of thechemicals in the fluids used in hydraulic fracturing or well stimulation operations. Additionally, some states, localities and local regulatory districts haveadopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling andcompletion operations, including requirements regarding permitting, casing and cementing of wells; testing of nearby water wells; restrictions on access to,and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Although none of the Company’sproperties are in jurisdictions where the moratoria have been imposed, it is possible the jurisdictions where the Company’s properties are located may adoptsuch limits or other limits on hydraulic fracturing in the future. In December 2017, BLM rescinded regulations that it previously enacted for hydraulicfracturing activities on federal lands; that rescission has been challenged by several environmental groups and states in ongoing litigation. Further, the EPAhas announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturingchemicals and is working on regulations for wastewater generated by hydraulic fracturing.Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In Oklahoma,for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources ofseismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation ofunderground injection wells. Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns aboutseismic activity from well injection in jurisdictions where we operate could affect our operations.Superfund. Under the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the“Superfund” law, liability, generally, is joint and several for costs of investigation and remediation and for natural resource damages, without regard to faultor the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLAas hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include current and certainpast owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance, persons who disposed of or arranged forthe disposal of the Hazardous Substances found at such a facility, and in some cases the parties transporting such Hazardous Substances to the facility atissue. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to releases and threats of releases to protect the publichealth or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from thedefinition of Hazardous Substance, in the course of its operations, adulterated petroleum products containing other Hazardous Substances have been treatedas Hazardous Substances in the past, and the Company has generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances.The Company may also be an owner or operator of facilities on which Hazardous Substances have been released. The Company may be responsible underCERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages, as a past or presentowner or operator or as an arranger. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons orother wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have beentaken for disposal. In addition, a portion of these properties may have been operated by third parties whose treatment and disposal or release of wastes was notunder our control. Many states have comparable laws imposing liability on similar classes of persons for releases, including for releases of materials that maynot be included in CERCLA’s definition of Hazardous Substances. To its knowledge, the Company has not been named a PRP under CERCLA (or anycomparable state law) nor have any prior owners or operators of its properties been named as PRPs related to their ownership or operation of such property.National Environmental Policy Act. The federal National Environmental Policy Act provides that, for federal actions significantly affecting thequality of the human environment, the federal agency taking such action must prepare an Environmental Assessment (“EA”) or an environmental impactstatement (“EIS”). In the EIS, the agency is required to evaluate alternatives to the proposed action and the environmental impacts of the proposed action andof such alternatives. Actions of the Company, such as drilling on federal lands, to the extent the drilling requires federal approval, may trigger therequirements of the National Environmental Policy Act, including the requirement that an EA or EIS be prepared. The requirements of the NationalEnvironmental Policy Act may result in increased costs, significant delays and the imposition of restrictions or obligations on the Company’s activities,including but not limited to the restricting or prohibiting of drilling.Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act (“CWA”), imposescertain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threateningUnited States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of anoil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a dischargingfacility is located. OPA assigns liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and for avariety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oildischarge or substantial threat of discharge, the Company could be liable for costs and damages.10Table of Contents Clean Air Act. The Clean Air Act (“CAA”) regulates emissions of six criteria pollutants from stationary and mobile sources and establishes NationalAmbient Air Quality Standards (“NAAQS”) for the pollutants of concern. The CAA is a federal law, but states, tribes and local governments do much of thework to develop EPA-approved plans to achieve these standards and meet the CAA’s requirements. Federal and state laws generally require new and modifiedsources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent emission controls.Administrative agencies can bring actions for failure to comply with air pollution regulations or permits and generally enforce compliance throughadministrative, civil or criminal enforcement actions, which may result in fines, injunctive relief and imprisonment.The New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs under the CAAimpose specific requirements affecting the oil and gas industry under both programs for compressors, controllers, dehydrators, storage tanks, natural gasprocessing plants, completions and certain other equipment. Periodic review and revision of these rules by federal and state agencies may require changes toour operations, including possible installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.In May 2016, the EPA finalized rules to reduce methane and volatile organic compound (“VOC”) emissions from new, modified or reconstructedsources in the oil and natural gas sector; however, in September 2018, under a new administration, the EPA proposed amendments that would relaxrequirements of the rules. Similarly, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it had previouslyenacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; California and New Mexico havechallenged the new rule in ongoing litigation. In addition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPAto establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. Several states arepursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in May2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicableto the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent airpermitting requirements and cause major delays in construction, effectively depressing new development. Compliance with these and other air pollutioncontrol and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, whichcould be significant.Clean Water Act. The Clean Water Act (“CWA”) and analogous state laws restrict the discharge of pollutants, including produced waters and other oiland natural gas wastes, into waters of the United States, a term broadly defined to include, among other things, certain wetlands. Under the Clean Water Act,permits must be obtained for the discharge of pollutants into waters of the United States. The CWA provides for administrative, civil and criminal penaltiesfor unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for thecosts of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varyingcivil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, intostate waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated withconstruction activities.The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit. In September 2015, the EPA and theArmy Corps of Engineers (“Corps”) issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands (the “Clean Water Rule”). TheClean Water Rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals, but on January 22, 2018, the U.S. Supreme Court ruled that jurisdictionto hear challenges to the rule lies with the federal district courts, and the Sixth Circuit’s stay was dissolved in February 2018. On July 27, 2017, the EPApublished a proposed rule to rescind the Clean Water Rule and re-codify the regulatory text that existed prior to 2015 defining the “waters of the UnitedStates,” for which the EPA and the U.S. Department of the Army established a non-regulatory docket to solicit written recommendations for the rulemaking,which closed on November 28, 2017. On February 6, 2018, the EPA and the Corps finalized a two-year postponement of the effective date of the Clean WaterRule to February 6, 2020. On August 16, 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction against EPA’s and theCorps’ postponement of the Clean Water Rule, making the rule effective in 26 states, certain of which have asked the U.S. District Court for the SouthernDistrict of Texas to postpone the rule nationwide. To the extent the Clean Water Rule is enforced in jurisdictions in which we operate or a replacement ruleexpands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fillactivities in wetland areas. In December 2018, EPA released revisions to the definition of WOTUS, specifically excluding “ephemeral” features that existonly during precipitation events and removing any groundwater features. These revisions are anticipated for finalization in 2019. Until that time, regulationsare being implemented as they were prior to August 2015.Also, in 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities fromsending wastewater to publicly-owned treatment works, permitting several years until compliance will be enforced. This pending restriction of disposaloptions for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.11Table of Contents Endangered Species Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if aspecies is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections areoffered to migratory birds under the Migratory Bird Treaty Act, and special protections are provided to bald and golden eagles under the Bald and GoldenEagle Protection Act. The Company conducts operations on federal and other oil and natural gas leases that have species, such as raptors, that are listed andspecies, such as sage grouse, that could be listed as threatened or endangered under the ESA. In the case of sage grouse, in October 2017, the U.S. Fish andWildlife Service announced the beginning of a scoping process to solicit public comments on Greater Sage-Grouse land management that could warrant landplan use amendments relating to the sage grouse. On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how itidentifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal andprivate land use and could delay or prohibit land access or development. Moreover, as a result of a settlement approved by the U.S. District Court for theDistrict of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make listing decisions and critical habitat designations wherenecessary for over 250 species. The U.S. Fish and Wildlife Service issued a 7-Year National Listing Workplan in September 2016. However, on July 25,2018, the U.S. Fish and Wildlife Service proposed three revisions to regulations regarding critical habitat designation, interagency cooperation, andprotection of threatened species that it believes are necessary to address industry and landowner concerns. The U.S. Department of the Interior also issued anopinion on December 22, 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In response to this opinion, twoseparate lawsuits were filed on May 24, 2018 in the U.S. District Court for the Southern District of New York challenging the Department of the Interior’sinterpretation of the MBTA. On September 5, 2018, eight states also filed suit in the U.S. District Court for the Southern District of New York on the relevantissue. The identification or designation of previously unprotected species as threatened or endangered in areas where our operations are conducted couldcause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have anadverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it couldadversely impact the value of our leases.Climate Change Legislation. More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”), including methane andcarbon dioxide, may be adopted and could cause the Company to incur material expenses in complying with them. In the absence of comprehensive federallegislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down thepermitting requirements as applicable to GHG emissions, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissionsof other pollutants. The EPA has established GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources tomonitor, maintain records on, and annually report their GHG emissions. The Company has submitted all required annual reports to date. Although the ruledoes not limit the amount of GHGs that can be emitted, it could require us to incur significant costs to monitor, keep records of, and report GHG emissionsassociated with our operations.In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and a number of state and regional effortshave emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Cap and trade programs typically require majorsources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States wasone of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emissionreduction goals beginning in 2020. However, on June 1, 2017, President Trump announced that the United States will withdraw from the Paris Agreement,and on August 4, 2017, the U.S. State Department officially informed the United Nations of its intent to withdraw from the Paris Agreement as of November 4,2020 unless the agreement is renegotiated. Various states and local governments have vowed to continue to enact regulations to achieve the goals of theParis Agreement.Any legislation or regulatory programs to reduce GHG emissions could also increase the cost of consuming, and thereby reduce demand for, the oil andnatural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business,financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climatechange could reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directedtheir attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting oreliminating their investment in oil and natural gas activities. Finally, it should be noted that many scientists have concluded that increasing concentrationsof GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms,floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by ourcustomers or otherwise cause us to incur significant costs in preparing for or responding to those effects.Worker Safety. The Occupational Safety and Health Act (“OSHA”) and analogous state laws regulate the protection of the safety and health ofworkers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations andprovision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. For example, under a new OSHAstandard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below thenew limits by June 23, 2021. Failure to comply with OSHA requirements can lead to the imposition of penalties. In December 2015, the U.S. Departments ofJustice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.The Company believes that it is in substantial compliance with current applicable environmental and occupational health and safety laws andregulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.12Table of Contents EmployeesAs of December 31, 2018, the Company had 151 full-time employees, including officers. The Company believes that its relationship with itsemployees is satisfactory.Seasonality and CyclicalitySeasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in the areas in which theCompany operates. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, suppliesand personnel, which could lead to shortages and increase costs or delay operations. For example, the Company’s operations may be impacted by ice andsnow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimeslessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winterrequirements during the summer, which can also lessen seasonal demand fluctuations. As a corollary, the demand for our products can be impacted byweather in the western United States from temperature fluctuations outside of normal ranges, moisture levels in the Pacific Northwest to the extent it impactshydroelectric power generation, and more broadly across the United States when there are unusual cold events or lack of winter weather.CompetitionThe oil and gas industry is intensely competitive, and we compete with other companies in our industry that have more extensive resources than we door that may have other competitive advantages or disadvantages. We compete with other companies in the acquisition of properties, in the search for anddevelopment of reserves, in the production and sale of natural gas and crude oil, and for the labor and equipment required to conduct our operations. Ourcompetitors include major oil and natural gas companies, other independent oil and natural gas companies, and individual producers and operators.Principal Executive OfficesThe Company is incorporated under the laws of Yukon, Canada, with headquarters in Englewood, Colorado. The principal executive offices arelocated at 116 Inverness Drive East, Suite 400, Englewood, Colorado. The main telephone number is (303) 708-9740.Item 1A.Risk Factors.An investment in our common stock involves certain risks. If any of the following key risks were to occur, it could have a material adverse effect onour financial position, results of operations, and cash flows. In any such circumstance and others described below, the trading price of our securities coulddecline and investors could lose part or all of their investment. We have significant indebtedness. Our level of indebtedness could adversely affect our business, results of operations, and financial condition. If we areunable to comply with the financial and non-financial covenants governing our indebtedness or obtain waivers of any defaults that occur with respect toour indebtedness, or amend, replace or refinance any or all of the agreements governing our indebtedness and/or otherwise secure additional capital, wemay be unable to meet our expenses and debt obligations.At February 28, 2019, we had the following obligations outstanding under our Revolving Credit Facility, our Term Loan Facility (as defined in Note6), our Second Lien Notes, 2022 Notes and our 2025 Notes: •$41 million due January 12, 2022 under the Revolving Credit Facility; •$975 million due April 12, 2024 under the Term Loan Facility; •$572 million due July 12, 2024 with respect to the Second Lien Notes; •$150 million due April 12, 2022 with respect to the 2022 Notes; and •$225 million due April 12, 2025 with respect to the 2025 Notes.Our indebtedness affects our operations in several ways, including: •requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available tofinance our operations and other business activities, and limiting our flexibility in planning for or reacting to changes in our business and theindustry in which we operate; •increasing our vulnerability to economic downturns and adverse developments in our business; •limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capitalexpenditures or acquisitions or to refinance existing indebtedness; •placing restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in businesscombinations;13Table of Contents •placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or lessrestrictive terms governing their indebtedness; •limiting our ability to deduct our net interest expense; and •making it more difficult for us to satisfy our obligations under our existing indebtedness and increasing the risk that we may default on our debtobligations.Our ability to meet our expenses and debt service obligations will depend on our future performance, which will be affected by financial, business,economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. Wedepend on our Revolving Credit Facility for future capital and liquidity needs, because we use operating cash flows for investing activities and borrow asneeded. We cannot be certain that our cash flow or liquidity will be sufficient to allow us to pay the principal and interest on our outstanding indebtednessand meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing indebtedness, sell assets, borrowmore money or raise equity. We may not be able to refinance our existing indebtedness, sell assets, borrow more money or raise equity on terms acceptable tous, if at all. Our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from ouroperations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under ourindebtedness, and such an event of default could materially and adversely affect our business, financial condition and results of operations.There are covenants in the agreements governing our indebtedness. In many instances, a default under one of the agreements governing ourindebtedness can, if not cured or waived, result in a default under certain of our other indebtedness agreements. A default on our obligations and/or anacceleration of our indebtedness by our lenders or noteholders, as applicable, would have a material adverse impact on our business, financial condition,results of operations, cash flows, and the trading price of our securities.Under the Fourth Amendment to the Revolving Credit Facility, Ultra Resources is required to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii)a current ratio, including the unused portion of the Revolving Credit Facility, of 1.00 to 1.00; (iii) a net leverage ratio of 4.50 to 1.00 as of December 31,2018, 4.75 to 1.00 as of March 31, 2019 through June 30, 2019, 4.90 to 1.00 as of September 30, 2019 through June 30, 2020, 4.50 to 1.00 as of September30, 2020, and 4.25 to 1.00 as of December 31, 2020 and each other fiscal quarter end thereafter; and (iv) after the Company has obtained investment graderating, an asset coverage ratio of 1.50 to 1.00. At December 31, 2018, we were in compliance with all of our debt covenants under our Revolving CreditFacility. Should the independent auditor conclude that a going concern modification explanatory paragraph would be required as of an annual audit period,such an item would be deemed a covenant violation under the Revolving Credit Facility and the Term Loan Facility. A violation of this covenant canbecome an event of default under our debt agreements and result in the acceleration of all of our indebtedness. If our lenders or our noteholders accelerate the payment of amounts outstanding under our Revolving Credit Facility, the Term Loan Facility, theSecond Lien Notes or the Unsecured Notes, respectively, we do not currently have sufficient liquidity to repay such indebtedness and would need additionalsources of capital to do so. We could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, we cannot provide any assurances that we will be successful in obtainingcapital from such transactions on acceptable terms, or at all, and if we were unable to obtain sufficient additional capital to repay the outstandingindebtedness and sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under chapter 11 or theCanadian Bankruptcy and Insolvency Act, or an involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada.The borrowing base under our Revolving Credit Facility may be reduced, which could limit us in the future. In addition, the liquidity under ourRevolving Credit Facility may be more limited than the borrowing base availability due to the consolidated net leverage financial covenant.The borrowing base under our Revolving Credit Facility is currently $1.3 billion, and lender commitments under our Revolving Credit Facility are$325.0 million based on the recent borrowing base redetermination. The borrowing base is redetermined semi-annually under the terms of our RevolvingCredit Facility on April 1 and October 1. The April 1, 2019 redetermination was accelerated by the Company and has been completed as of the date of thisfiling. The next regularly scheduled redetermination is October 1, 2019. In addition, either we or the lenders may request an interim redetermination twice ayear or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower commodity prices,operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness, or for any other reason. In the event of adecrease in our borrowing based due to declines in commodity prices or otherwise, our ability to borrow under the Revolving Credit Facility may be limitedand we could be required to pay indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debtcapital markets, including the market for senior unsecured notes, to meet our obligations, including any such debt repayment obligations.Moreover, while our current borrowing base and the amount outstanding under the Revolving Credit Facility may indicate sufficient liquidity, theamount that we may borrow under the Revolving Credit Facility is governed by compliance with the consolidated net leverage covenant as discussedabove. The calculation of this covenant may result in the Company having less effective liquidity, thereby negatively impacting the Company’s ability tooperate in an unencumbered manner and may create a risk of continuing as a going concern.14Table of Contents Failure to maintain the continued listing standards of NASDAQ could result in delisting of our common shares, which could negatively impact themarket price and liquidity of our common shares and our ability to access the capital markets. Our common shares are listed on the NASDAQ Global Select Market (“NASDAQ”) and the continued listing of our common shares on NASDAQ issubject to our ability to comply with NASDAQ’s continued listing requirements, including, among other things, the requirement to hold an annualshareholders’ meeting and the minimum closing bid price requirement of $1.00 per common share. On January 2, 2019, we received written notice from the Listing Qualifications Department of NASDAQ notifying us that we no longer comply withNASDAQ Listing Rule 5620(a) due to the Company’s failure to hold an annual meeting of shareholders within twelve months of the end of the Company’sfiscal year ended December 31, 2017. On February 1, 2019, we submitted to NASDAQ a plan to regain compliance with the annual shareholders meetingrequirement by holding a combined annual meeting of shareholders for 2018 and 2019 on May 22, 2019, and NASDAQ accepted our plan of compliance. In addition, on January 29, 2019, we received written notice from the Listing Qualifications Department of NASDAQ notifying us that our commonshares closed below the $1.00 per share minimum bid price required by NASDAQ Listing Rule 5450(a)(1) for 30 consecutive business days and that we havea period of 180 calendar days in which to regain compliance. We are actively monitoring the bid price of our common shares and considering options to regain compliance with the minimum bid price requirement.If we are unable to regain compliance, however, any delisting from NASDAQ could result in even further reductions in our price per common share,substantially limit the liquidity of our common shares, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancingor other transactions on acceptable terms, or at all. Delisting from the NASDAQ could also have other negative results, including the potential loss ofinstitutional investor interest and fewer business development opportunities. There is no assurance that we will continue to maintain compliance with NASDAQ continued listing standards. Our business has been and maycontinue to be affected by worldwide macroeconomic factors, which include uncertainties in the credit and capital markets as well as with respect tocommodity prices. External factors that affect our share price, such as liquidity requirements of our investors, as well as our performance, could impact ourmarket capitalization, revenue and operating results, which, in turn, affect our ability to comply with the NASDAQ’s listing standards. The NASDAQ has theability to suspend trading in our common shares or remove our common shares from listing on the NASDAQ if, in the opinion of NASDAQ: (a) our financialcondition and/or operating results appear to be unsatisfactory; (b) it appears that the extent of public distribution or the aggregate market value of ourcommon shares has become so reduced as to make further dealings on the exchange inadvisable; (c) we have sold or otherwise disposed of our principaloperating assets, or have ceased to be an operating company; (d) we have failed to comply with our listing agreements with the exchange; or (e) any otherevent shall occur or any condition shall exist which makes further dealings on the exchange unwarranted.If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.Our business strategy has historically included maintaining a portfolio of properties that provide long-term, profitable growth through development inareas that support sustainable, lower-risk, repeatable, high-return drilling projects. In the future, we may not be able to obtain financing in sufficient amountsor on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implementour historical business strategy, we may be required to curtail operations, which could adversely affect our financial condition and results of operations. Our substantial indebtedness, liquidity concerns, the credit ratings assigned to our debt by independent credit rating agencies and historicalemergence from bankruptcy in 2017 could adversely affect our business and relationships.Our substantial indebtedness, liquidity concerns, the credit ratings assigned to our debt by independent credit rating agencies and our historicalemergence from chapter 11 bankruptcy proceedings in 2017 could adversely affect our business and relationships with customers, employees, andsuppliers. Due to uncertainties, many risks exist, including the following: •key suppliers could terminate their relationship or require financial assurances or enhanced performance; •the ability to renew existing contracts and compete for new business may be adversely affected; •the ability to attract, motivate, and/or retain key executives and employees may be adversely affected; •employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and •competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.The occurrence of one or more of these events could have a material and adverse effect on our operations, financial conditions, and reputation. Wecannot assure you that having been subject to bankruptcy protections will not adversely affect our operations in the future.15Table of Contents Transfers or issuances of our equity may impair our ability to utilize our income tax net operating loss carryforwards in future years.Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years.We have U.S. federal net operating loss carryforwards of approximately $2.2 billion as of December 31, 2018. Our ability to utilize our net operating losscarryforwards to offset future taxable income and to reduce federal income tax liability may be substantially limited if we experience an “ownership change,”as defined in section 382 of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), which could have a negative impact on our financial positionand results of operations. Generally, there is an “ownership change” if one or more shareholders owning 5% or more of a corporation’s common stock haveaggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. An “ownership change” occurredwhen our chapter 11 plan of reorganization became effective. A further “ownership change” is possible now that we have emerged from chapter 11. Undersection 382 of the Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its pre-ownership change netoperating losses that may be utilized to offset future taxable income generally will be subject to an annual limitation equal to the value of its stockimmediately prior to the ownership change multiplied by the long-term tax-exempt rate, plus an additional amount calculated based on certain “built ingains” in our assets that may be deemed to be realized within a 5-year period following any ownership change. The ownership change that occurred as aresult of our exit from chapter 11 proceedings should not materially limit our ability to utilize our net operating loss carryforwards, but it may be affected byfuture ownership changes, if any. In addition, under the tax reform bill commonly known as Tax Cuts and Jobs Act (the “Tax Act”), which was signed intolaw on December 22, 2017, (i) the amount of post-2017 net operating losses that we are permitted to deduct in any taxable year is limited to 80% of ourtaxable income in such year, where taxable income is determined without regard to the net operating loss deduction itself, and (ii) post-2017 net operatinglosses cannot be carried back to prior taxable years. There can be no assurance that we will be able to utilize our federal income tax net operating loss carry-forwards to offset future taxable income.Our operations could be adversely affected if we fail to maintain required bonds.Federal and state laws require bonds or cash deposits to secure our obligations with respect to various parts of our operations. Our failure to maintain, orinability to acquire, bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety offactors including: (i) our failure to comply with rules and regulations of federal and state governmental agencies, including the BLM, (ii) the lack ofavailability of bonding, higher expense or unfavorable market terms of new bonds; (iii) and the exercise by third-party bond issuers of their right to refuse torenew the bonds. If we fail to maintain required bonds, our production may significantly decrease, which would significantly decrease our alreadyconstrained cash flow.Liquidity concerns could result in a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current orfuture financings or trade credit.Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned toour debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of timeor that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our creditratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, coststructure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increaseour borrowing costs and potentially require us to post letters of credit for certain obligations.We cannot control the future price of oil and natural gas and sustained periods of low prices could hurt our profitability and financial condition andcould impair our ability to grow our business or to perform the obligations in our agreements, including the agreements governing our indebtedness.Sustained periods of low commodity prices will adversely affect our operations and financial condition. Our revenues, profitability, liquidity, ability toraise capital for our business, future growth, ability to operate, develop and explore our properties, and the carrying value of our properties depend heavily onprevailing prices for oil and natural gas.Natural gas comprised approximately 95% of our total production and 81% of our consolidated revenue for the year ended December 31, 2018 andrepresented 95% of our total proved reserves as of December 31, 2018. Historically, natural gas prices have been highly volatile, including in the RockyMountain region of the United States where the vast majority of our natural gas is produced. Prices have been affected by actions of federal, state and localgovernments and agencies, foreign governments, national and international economic and political conditions, levels of consumer demand, weatherconditions, domestic and foreign supply of oil and natural gas, proximity and capacity of gas pipelines and other transportation facilities, the price andavailability of equipment, materials and personnel to conduct operations, and the price and availability of alternative fuels. These external factors and thevolatile nature of the energy markets make it difficult to estimate future prices of natural gas. Any substantial or extended decline in the price of natural gaswill have a material adverse effect on our financial condition and results of operations, including reduced cash flow and borrowing capacity, and lowerproved reserves. Price volatility also makes it difficult to budget for and project the return on potential acquisitions and development and explorationprojects, and sustained lower gas prices have caused and may, in the future continue to cause, us or the operators of properties in which we have ownershipinterests to curtail projects and limit or suspend drilling, completion or even production activities.16Table of Contents Crude oil comprised approximately 5% of our total production and 17% of our consolidated revenue for the year ended December 31, 2018 andrepresented 5% of our total proved reserves as of December 31, 2018. Crude oil prices declined substantially in the second half of 2014, with sustained lowerprices continuing throughout 2015, 2016, and 2017, and prices remaining volatile during the year ended December 31, 2018. In the future, crude oil pricesmay remain at current levels or fall to lower levels. If crude oil prices remain at current levels or fall to lower levels, this will adversely affect our crude oiloperations and our financial condition. Most of the production from our Uinta Basin properties was crude oil.In addition, because we are significantly leveraged, a substantial decrease in our revenue due to low commodity prices is currently impairing and mayin the future continue to impair our ability to satisfy payment obligations on our indebtedness and reduce funds available for operations and future businessopportunities.A substantial or extended decline in oil and natural gas prices may continue indefinitely, and may adversely affect our business, financial condition orresults of operations and our ability to meet our capital expenditure obligations, our debt repayment and service obligations, and our financialcommitments.The price we receive for our oil and natural gas heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and naturalgas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically,the markets for oil and natural gas have been volatile and we expect this volatility to continue for the foreseeable future. For example, during the period fromJanuary 1, 2014 to December 31, 2018, NYMEX West Texas Intermediate oil prices ranged from a high of $107.31 per Bbl to a low of $27.57 per Bbl.Average daily prices for NYMEX Henry Hub gas ranged from a high of $5.30 per MMBtu to a low of $1.65 per MMBtu during the same period. Additionally,the price differential for natural gas can also vary significantly. Over this same period, average monthly prices for NwRox ranged from a high of $6.92 perMmbtu to a low of $1.50 per Mmbtu. This near-term volatility may affect future prices in 2019 and beyond. The volatility of the energy markets makes itdifficult to predict future oil and natural gas price movements with any certainty.The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include thefollowing: •worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas; •the actions of the Organization of Petroleum Exporting Countries; •the price and quantity of imports of foreign oil and natural gas; •political conditions in or affecting other oil and natural gas-producing countries; •the level of global oil and natural gas exploration and production; •the level of global oil and natural gas inventories; •localized supply and demand fundamentals and transportation availability; •weather conditions and natural disasters; •government policies to discourage use of fuels that emit “greenhouse gases” (“GHGs”) and encourage use of alternative energy; •domestic, local and foreign governmental regulations and taxes; •speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts; •price and availability of competitors’ supplies of oil and natural gas; •technological advances affecting energy consumption; •the availability of drilling rigs and completion equipment; and •the overall economic environment.Substantially all of our production is currently sold at market-based prices. Lower oil and natural gas prices will reduce our cash flows, borrowingability and the present value of our reserves. Lower oil and natural gas prices will reduce the amount of oil and natural gas that we can produce economically.Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations, and, may cause us tomake significant downward adjustments to our estimated proved reserves or to be unable to claim proved undeveloped reserves at all. If oil and natural gasprices remain at current levels or experience a substantial or extended decline from current levels, our future business, financial condition, results ofoperations, liquidity or ability to finance planned capital expenditures will be materially and adversely affected.17Table of Contents Our reserve estimates may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies inthese reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing ofdevelopment expenditures, including many factors beyond our control. The reserve data and standardized measures set forth herein represent only estimates.Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and theaccuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result,estimates of different engineers often vary. In addition, drilling, testing and production data acquired subsequent to the date of an estimate may justifyrevising such estimates. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered.Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success,the timing and identification of future drilling locations, commodity prices, future production levels, costs and the ability to finance future development thatmay not prove correct over time. Predictions of future production levels, development schedules (particularly with regard to non-operated properties),participation of joint working interest owners on projects, commodity prices and future operating costs are subject to great uncertainty, and themeaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based.The present value of net proved reserves included in this report should not be considered as the market value of the reserves attributable to ourproperties. In accordance with SEC requirements, we base the present value, discounted at 10%, of the pre-tax future net cash flows attributable to our netproved reserves on the average oil and natural gas prices during the 12-month period before the ending date of the period covered by this report determinedas an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for quality and transportation fees. Thecosts to produce the reserves remain constant at the costs prevailing on the date of the estimate. Actual current and future commodity prices and costs may bematerially higher or lower, and higher future costs and/or lower future commodity prices may impact whether development of our reserves in the future occursas scheduled or at all. In addition, the 10% discount factor, which the SEC requires us to use in calculating our discounted future net revenues for reportingpurposes, may not be the most appropriate discount factor based on our cost of capital from time to time and/or the risks associated with our business.Our producing properties are located in the Green River Basin in southwest Wyoming, making us vulnerable to risks associated with operating in asingle geographic area.All of our producing properties are geographically concentrated in the Green River Basin in southwest Wyoming. At December 31, 2018, all of ourtotal estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we are disproportionately exposed to theimpact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing ortransportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought-related conditions orinterruption of the processing or transportation of oil, natural gas or NGLs.Competitive industry conditions may negatively affect our ability to conduct operations.We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions andproduction include major integrated oil and natural gas companies as well as numerous independents, including many that have significantly greaterresources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospectsthan our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration,development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitableprospects for future exploration and development.Factors that affect our ability to compete in the marketplace include: •our access to the capital necessary to drill and complete wells and acquire properties; •our ability to acquire and analyze seismic, geological and other information relating to a property; •our ability to attract and retain the personnel necessary to properly evaluate seismic and other information relating to a property; •our ability to procure materials, equipment and services required to explore, develop and operate our properties; •our ability to comply with administrative, regulatory and other governmental requirements; and •our ability to access pipelines, and the locations of facilities used to produce and transport oil and natural gas production.18Table of Contents Factors beyond our control affect our ability to effectively market production and may ultimately affect our financial results.The ability to market oil and natural gas depends on numerous factors beyond our control. These factors include: •the extent of domestic production and imports of oil and natural gas; •the availability of pipeline, rail and refinery capacity, including facilities owned and operated by third parties; •the availability of a market for our oil and natural gas production; •the availability of satisfactory transportation arrangements for our oil and natural gas production; •the proximity of natural gas production to natural gas pipelines; •the effects of inclement weather; •the demand for oil and natural gas by utilities and other end users; •the availability of alternative fuel sources; •state and federal regulations of oil and natural gas marketing and transportation; and •federal regulation of natural gas sold or transported in interstate commerce.Because of these factors and other factors beyond our control, we may be unable to market all of the oil and natural gas that we produce or obtainfavorable prices for such production.Our business relies on certain key personnel.Our management believes that our continued success will depend to a significant extent upon the efforts and abilities of certain of our key personnel.The loss of the services of any of these key personnel could have a material adverse effect on our business. We do not maintain “key man” life insurance onany of our officers or other employees.Any derivative transactions we enter into may limit our gains and expose us to other risks such as taxes and royalties.We may enter into financial derivative transactions from time to time to manage our exposure to commodity price risks. These transactions limit ourpotential gains if commodity prices rise above the levels established by our derivative transactions. These transactions may also expose us to other risks offinancial losses, for example, if our production is less than we anticipated at the time we entered into a derivative instrument or if a counterparty to ourderivative instruments fails to perform its obligations under a derivatives transaction. We pay royalties and taxes based on physical production; therefore, ifwe have utilized derivative transactions on a high percentage of our forecast production, we may have royalty and tax burdens that are significantly higherthan the derivative price settled for that month’s production. Legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.Title VII of the Dodd–Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation ofover-the-counter (“OTC”) derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulationsaffecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/orexemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on November 5, 2013,a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are theireconomic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such hedging transactions satisfythe CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule on margin requirements for swaptransactions, which proposes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting theirbusiness, from any requirement to post margin to secure such swap transactions. In addition, the CFTC has issued a final rule authorizing an exception forcommercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear allswap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-Frank Act alsoimposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the aboveregulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatilityand other commercial risks affecting our business.19Table of Contents While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or margin requirements, depending onthe Company’s ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate itscommercial risks, these rules and regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with our financial derivative activities. The Dodd-Frank Act may require our current counterparties to post additionalcapital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities,which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changescould reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives tohedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost ofderivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operationspurposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce theavailability of derivatives to protect against commercial risks we encounter.Compliance with environmental and occupational safety and health laws and other government regulations could be costly and could negativelyimpact our production.Our operations are subject to numerous and complex laws and regulations relating to environmental and occupational protection. These laws andregulations, which are continuously being reviewed for amendment and/or expansion, may: •require that we acquire permits before developing our properties; •restrict the substances that can be released into the environment in connection with drilling, completion and production activities; •limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and •require remedial measures to mitigate pollution from former operations, including plugging previously abandoned wells.Under these laws and regulations or under the common law, we could be liable for personal injury and clean-up costs and other environmental, naturalresource and property damages, as well as administrative, civil and criminal penalties or injunctions. Failure to comply with these laws and regulations couldalso result in the occurrence of delays or restrictions in permitting or performance of projects, or the issuance of orders and injunctions limiting or preventingoperations relating to our properties in some areas. Under certain environmental laws and regulations, an owner or operator of our properties could be subjectto strict, joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination, regardlessof whether the owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at thetime the release or contamination occurred. Private parties, including the owners of properties upon which wells are drilled or facilities where petroleumhydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, to seek damages forcontamination or for personal injury or property damage. We maintain limited insurance coverage for sudden and accidental environmental damages, but donot maintain insurance coverage for the full potential liability that could be caused by accidental environmental damages. Accordingly, we may be subject toliability in excess of our insurance coverage or may be required to cease production from properties in the event of material environmental damages.We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and otherequipment emissions, greenhouse gases and hydraulic fracturing. Changes in environmental laws and regulations occur frequently, and any changes thatresult in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completionactivities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements could require significant expenditures by Ultra orother operators of the properties to attain and maintain compliance and may otherwise have a material adverse effect on the results of operations, competitiveposition or financial condition of Ultra or such other operators. Increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2017-2019 National Enforcement Initiatives, through which the EPA will purportedly address incidences of noncompliance from natural gas extraction andproduction activities that may cause or contribute to significant harm to public health and/or the environment. In addition, government disruptions, such asan extended federal government shutdown resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debtceiling, could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations.A significant percentage of our operations are conducted on federal and state lands. These operations are subject to a wide variety of regulations as wellas other permits and authorizations which must be obtained from and issued by state and federal agencies. To conduct these operations, we may be requiredto file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Complying with any ofthese requirements may adversely affect our ability to complete our drilling programs at the costs and in the time periods anticipated.20Table of Contents Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil andgas we produce.More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to complywith such laws and regulations. In the absence of comprehensive federal legislation on GHG emission control, the EPA requires the permitting of GHGemissions for certain sources that require permits due to emissions of other pollutants. The EPA also requires the reporting of GHG emissions from specifiedlarge GHG emission sources including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission,storage and distribution facilities, which may include facilities we operate. Reporting of GHG emissions from such facilities is required on an annual basis.We will continue to incur costs associated with this reporting obligation.In May 2016, the EPA finalized rules to reduce methane emissions and VOC from new, modified or reconstructed sources in the oil and natural gassector; however, in September 2018, under a new administration, the EPA proposed amendments that would relax requirements of the rules. Similarly, inSeptember 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it previously enacted to reduce methane emissions fromventing, flaring, and leaks during oil and gas operations on public lands; California and New Mexico have challenged the new rule in ongoing litigation. Inaddition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methaneemissions from existing sources in the oil and natural gas sector; that lawsuit is pending. Several states are pursuing similar measures to regulate emissions ofmethane from new and existing sources within the oil and natural gas source category. In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states and regions have already taken legalmeasures to reduce or measure GHG emission levels, often involving the planned development of GHG emission inventories and/or regional cap and tradeprograms. Most of these cap and trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances.The number of allowances available for purchase is reduced each year in an effort to reduce overall GHG emissions. The cost of these allowances couldescalate significantly over time. On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement inParis, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHGemissions targets. Although the present administration has announced its intention to withdraw from the Paris accord, several states and local governmentsremain committed to its principles in their effectuation of policy and regulations. It is not possible at this time to predict if, how or when the United States orstates might impose restrictions on GHGs as a result of the international climate change agreement. The adoption and implementation of any legislation orregulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incurcosts to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Moreover,incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas weproduce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies,which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gasactivities.Potential physical effects of climate change could adversely affect our operations and cause us to incur significant costs in preparing for or respondingto those effects.In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather(including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration andproduction operations, including the hydraulic fracturing of our wells, have the potential to be adversely affected. Potential adverse effects could includedisruption of our production activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operationor reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significantphysical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process relatedservices provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recoverthrough insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.Federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including with respect to water use and waste disposal, couldresult in increased costs and additional operating restrictions or delays.Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injectionof water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated bystate oil and gas commissions; however, the EPA has taken certain actions with respect to regulating hydraulic fracturing. For example, the EPA publishedpermitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and additional CAAregulations in May 2016 governing performance standards for the oil and natural gas industry, for which the EPA in September 2018 has proposedamendments that would relax requirements of the regulations; issued in June 2016 final effluent limitations guidelines under the CWA that waste water fromshale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant; and issued in 2014 a prepublication of its AdvanceNotice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing.Also, the BLM published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal andIndian lands. However,21Table of Contents following years of litigation, the BLM rescinded the rule in December 2017; a lawsuit challenging the rule rescission is pending. The BLM also issued rulesin November 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands, although the present administrationis proposing to delay the implementation dates applicable to the requirements under these rules. The BLM also issued rules in November 2016 to limitmethane emissions from new and existing oil and gas operations on federal lands, but subsequently relaxed and rescinded certain requirements of the rules inSeptember 2018; a lawsuit challenging the September 2018 rule revision is pending.From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and torequire disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states have adopted, and other states are considering adopting,regulations that could restrict hydraulic fracturing in certain circumstances. Wyoming has adopted regulations requiring producers to provide detailedinformation about wells they hydraulically fracture in that state. Some states have adopted or are considering adopting regulations requiring disclosure ofchemicals in fluids used in hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing andcementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may beused in hydraulic fracturing operations. Any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult orcostly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable. In addition, if hydraulicfracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and alsoto associated permitting delays and potential increases in costs. We have conducted hydraulic fracturing operations on most of our existing wells, and weanticipate conducting hydraulic fracturing operations on substantially all of our future wells. As a result, restrictions on hydraulic fracturing could reduce theamount of oil and natural gas that we are ultimately able to produce in commercial quantities and adversely affect our operations and financial condition.In addition, hydraulic fracturing operations require the use of a significant amount of water. The inability to locate sufficient amounts of water, ordispose of or recycle water used in drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives andregulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limitedto, produced water, drilling fluids and other wastes associated with the development or production of natural gas.Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In Oklahoma,for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources ofseismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation ofunderground injection wells. Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns aboutseismic activity from well injection in jurisdictions where we operate could affect our operations.Changes in tax laws and regulations, including interpretations thereof, or in our operations may impact our effective tax rate and may adversely affectour business, financial condition and operating results.Tax interpretations, regulations, and legislation in the various jurisdictions in which we and our affiliates operate are subject to measurementuncertainty and the interpretations can impact net income, income tax expense or recovery, and deferred income tax assets or liabilities. In addition, tax rulesand regulations, including those relating to foreign jurisdictions, are subject to interpretation and require judgment by us that may be challenged by thetaxation authorities upon audit. In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws,including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not beenlimited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangibledrilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although theseprovisions were largely unchanged in the Tax Act, Congress could consider, and could include, some or all of these proposals as part of future tax reformlegislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed thatalso would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted,how soon any such changes could take effect. Changes in tax laws in any of the multiple jurisdictions in which we operate could result in an unfavorablechange in our effective tax rate, which could adversely affect our business, financial condition, and operating results.The effects of the Tax Act on our business could have an adverse effect on our net income.On December 22, 2017, the Tax Act was enacted and made significant changes to the Code. Such changes include a reduction in the corporate tax ratesand limitation on certain deductions and credits, among other changes. In addition, adverse changes in the underlying profitability and financial outlook ofour operations and changes in tax law could lead to changes in our valuation allowance against deferred tax assets on our balance sheets, which couldmaterially affect our results of operations. While we believe that the Tax Act will not impact the ability of our deferred tax assets, as re-measured, includingour significant U.S. federal net operating loss carryover, to reduce the amount or cash income taxes payable in the future, we continue to monitorclarifications and new regulations related to the Tax Act that could impact the Company.22Table of Contents Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.Our business has become increasingly dependent on digital technologies, including technologies operated by or under the control of third parties, toconduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gasreserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-partypartners. Unauthorized access to (or the loss of Company access to) our seismic data, reserves information or other proprietary information could lead to datacorruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all ofthe oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oiland gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets andmake it difficult or impossible to accurately account for production and settle transactions.While our operations and financial condition have not been materially and adversely affected by cyber-attacks, there is no assurance that we will notsuffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additionalresources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.Our business and the trading prices of our securities could be negatively impacted by the actions of so-called “activist” stockholders.If we become the subject of activity by activist shareholders, this could disrupt our business, distract our management and Board of Directors, andnegatively impact our business and the trading prices of our securities, including our common stock. Responding to shareholder activism can be costly andtime-consuming, disrupt our operations, and divert the attention of management and our employees from our strategic initiatives. Furthermore, activistcampaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities,harm our ability to attract new employees, investors, customers, and joint venture partners, and cause our stock price to experience periods of volatility.If a sustained financial or economic downturn occurs domestically or internationally, capital market conditions and commodity prices may deteriorate,which could materially and adversely affect our liquidity, results of operations and ability to execute our business.Global and domestic economic conditions are difficult for us to forecast and impossible for us to control. Similarly, conditions in global and domesticcapital markets, including debt and equity markets, are difficult for us to forecast and impossible for us to control. Adverse changes, even material adversechanges, in global and domestic economic conditions and in domestic and international capital markets may occur without warning. Although there are stepswe can take to anticipate and mitigate such changes, we may fail to do so. If we fail to successfully anticipate or mitigate such matters, adverse changes inglobal or domestic economic conditions or capital markets, especially materially adverse changes, could increase our costs, limit our financial flexibility, andmaterially and adversely affect our business, results of operations, and liquidity. Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time.Our future success depends on our ability to find, acquire, develop and produce additional oil and gas reserves that are economically recoverable.Without successful exploration, development or acquisition activities, our reserves and production will decline. We can give no assurance that we will beable to find, develop or acquire additional reserves at acceptable costs.We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capitalexpenditures to develop our existing reserves and to discover new oil and gas reserves.Our ability to continue exploration and development of our properties and to replace reserves depends upon our ability to comply with our debtcovenants, renegotiate our debt agreements, raise significant additional financing, or to seek and obtain other arrangements with industry participants in lieuof raising additional financing. Any arrangements that may be entered into could be expensive to us if such arrangements can be made at all. There can be noassurance that we will be able to raise additional capital in light of factors such as our financial condition, the market demand for our securities, the generalcondition of financial markets for independent oil and gas companies (including the markets for debt), oil and natural gas prices and general marketconditions. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and CapitalResources” for a discussion of our capital budget. Continued periods of depressed commodity prices or further commodity price decreases could have amaterial adverse effect on our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reservesand production. There can also be no assurance that we will be able to obtain other satisfactory arrangements to allow further exploration and development ofour properties if we are unable to raise additional capital.23Table of Contents We expect to use our cash from operations, cash from draws on the Revolving Credit Facility and cash on hand to fund our capital budget, ouroperating costs and our interest service obligations during 2019. The loan commitment and the aggregate amount of money that we can borrow under theRevolving Credit Facility and from other sources is revised from time to time based on certain restrictive covenants. A change in our ability to meet therestrictive covenants may limit our ability to borrow. If this occurred, we may have to sell assets or seek substitute financing. We can make no assurancesthat we would be successful in selling assets or arranging substitute financing. See Part II, Item 7 “Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Liquidity and Capital Resources” for information about our liquidity, available cash on hand, and the description ofthe current debt agreements.Our operations may be interrupted by severe weather or drilling restrictions.Our operations are conducted exclusively in the Rocky Mountain region of the United States. The weather in this area can be extreme and can causeinterruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions andsignificant capital investment. Likewise, our operations are subject to disruption from winter storms and severe cold, which can limit operations involvingfluids and impair access to our facilities.We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.The oil and natural gas business involves a variety of operating risks, including blowouts, fire, explosion, pipe failure, casing collapse, abnormallypressured formations, and environmental hazards such as oil spills, natural gas leaks, discharges of toxic gases, underground migration and surface spills ormishandling of fracture fluids, including chemical additives. The occurrence of any of these events with respect to any property we own or operate (in wholeor in part) could have a material adverse impact on us. We and the operators of our properties maintain insurance in accordance with customary industrypractices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained tocover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financialcondition.There are risks associated with our drilling activity that could impact our results of operations.Our oil and natural gas operations are subject to all of the risks and hazards typically associated with drilling, completion, production andtransportation of, oil and natural gas. These risks include the necessity of spending large amounts of money for identification and acquisition of propertiesand for drilling and completion of wells. In the drilling and completing of wells, failures and losses may occur before any deposits of oil or natural gas arefound and produced. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to beunsuccessful, resulting in a loss of our investment in such activity and possible liabilities. If oil or natural gas is encountered, there can be no assurance that itcan be produced in quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily.Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all.A prospect is an area in which our geoscientists have identified what they believe, based on available seismic and geological information, to beindications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill our prospects depends on many factors,including but not limited to: the availability and cost of capital; receipt of additional seismic data or reprocessing of existing data; material changes incurrent of future expected oil or natural gas prices; the costs and availability of drilling and completion equipment; the success or failure of wells drilled insimilar formations or which would use the same production facilities and equipment; changes in the estimates of costs to drill or complete wells; decisions ofour joint working interest owners; and regulatory, permitting and other governmental requirements. It is possible these factors and others may cause us toalter our drilling schedule or determine that a prospect should not be pursued at all.We have limited control over activities conducted on properties we do not operate.We own interests in properties that are operated by third parties. The success, timing and costs of drilling, completion, and other development activitieson our non-operated properties depend on a number of factors that are beyond our control. Because we have only a limited ability to influence and controlthe operations of our non-operated properties, we can give no assurances that we will realize our targeted returns with respect to those properties.24Table of Contents Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interferewith our ability to market the oil and natural gas that we produce.The marketability of our oil and natural gas production will depend in part on the availability, proximity and capacity of gathering and pipelinesystems owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such aspipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lackof contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In manycases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gatheringsystem or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business,results of operations, financial condition and prospects.We may fail to fully identify problems with any properties we acquire.We acquired a portion of our acreage position through property acquisitions and acreage trades, and we may acquire additional acreage in these orother regions in the future. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give noassurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate anyproblems we do identify.Our acquisitions may perform worse than we expected or prove to be worth less than what we paid because of uncertain factors and matters beyond ourcontrol. In addition, our acquisitions could expose us to potentially significant liabilities.When we make acquisitions of oil and gas properties, we make assumptions about many uncertain factors, including estimates of recoverable reserves,expected timing of recovering acquired reserves, future commodity prices, expected development and operating costs, and other matters, many of which arebeyond our control. Assumptions about uncertain factors may be wrong, and the properties we acquire may perform worse than we expect, materially andadversely affecting our operations and financial condition.Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results ofoperations.Since our business depends on the level of activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energytechnologies that increase the use of alternative forms of energy and reduce the demand for oil and natural gas could have a material adverse effect on ourbusiness, financial condition, and operations.Any future implementation of price controls on oil and natural gas would affect our operations.The United States Congress may in the future impose some form of price controls on either oil, natural gas, or both. Any future limits on the price of oilor natural gas could negatively affect the demand for our services and consequently, have a material adverse effect on our business, financial condition, andresults of operations.Damage to our reputation could damage our business.Our reputation is a critical factor in our relationships with employees, investors, customers, suppliers and joint venture partners. If we fail to address, orappear to fail to address, issues that give rise to reputational risk, including those described throughout this “Risk Factors” section, we could significantlyharm our reputation. Our reputation may also be damaged by how we respond to corporate crises. Corporate crises can arise from catastrophic events as wellas from incidents involving unethical behavior or misconduct; allegations of legal noncompliance; internal control failures; corporate governance issues;data breaches; workplace safety incidents; environmental incidents; media statements; the conduct of our suppliers or representatives; and other issues orincidents that, whether actual or perceived, result in adverse publicity. If we fail to respond quickly and effectively to address such crises, the ensuingnegative public reaction could significantly harm our reputation and could lead to increases in litigation claims and asserted damages or subject us toregulatory actions or restrictions.Damage to our reputation could negatively affect the demand for our services and consequently, have a material adverse effect on our business,financial condition, and results of operations. It could also reduce investor confidence in us, adversely affecting our stock price. Moreover, repairing ourreputation may be difficult, time-consuming and expensive.Forward-Looking StatementsThis report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, asamended (the “Securities Act”), Section 21E of the Exchange Act, and the Private Securities Litigation Reform Act of 1995. Except for statements ofhistorical facts, all statements included in this document, including those statements preceded by, followed by or that otherwise include the words “believe,”“expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on suchexpressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements arebased will prove to be correct.25Table of Contents Forward-looking statements include statements regarding: •our oil and natural gas reserve quantities, and the discounted present value of those reserves; •the amount and nature of our capital expenditures; •drilling of vertical and horizontal wells; •the timing and amount of future production and operating costs; •our ability to respond to low natural gas prices; •our levels of indebtedness •business strategies and plans of management; and •prospect development and property acquisitions.Some of the risks which could affect our future results and could cause results to differ materially from those expressed in our forward-lookingstatements include: •volatility and, especially, declines or substantial declines and weakness in natural gas or oil prices; •our ability to maintain adequate liquidity in view of current natural gas prices; •our ability to comply with the covenants and restrictions of the agreements governing our indebtedness, or our ability to amend or replace theagreements governing our indebtedness; •any future global economic downturn; •general economic conditions, including the availability of credit and access to existing lines of credit; •conditions in capital markets, including the availability of capital to companies in the oil and gas business; •the volatility of oil and natural gas prices; •the uncertainty of estimates of oil and natural gas reserves; •the impact of competition; •the availability and cost of seismic, drilling and other equipment; •our decisions about how we allocate capital and resources among strategic opportunities; •operating hazards inherent in the exploration for and production of oil and natural gas; •difficulties encountered during the exploration for and production of oil and natural gas; •difficulties encountered in delivering oil and natural gas to commercial markets; •changes in customer demand and producers’ supply; •the uncertainty of our ability to attract capital and obtain financing on favorable terms; •reductions in our borrowing base under our Revolving Credit Facility; •compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business, including thoserelated to climate change and greenhouse gases, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access toand the use of water, and financial derivatives and hedging activities; •actions of operators of our oil and natural gas properties; and •weather conditions.The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that couldaffect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements.26Table of Contents Item 1B.Unresolved Staff Comments.None.Item 2. Properties.Location and CharacteristicsThe Company owns oil and natural gas leases in Wyoming. The leases in Wyoming are primarily federal leases with 10-year lease terms untilestablishment of production. Production extends the lease terms until cessation of that production. The Company previously owned oil and natural gas leasesin Utah and Pennsylvania, which the Company sold in September 2018 and December 2017, respectively.Green River Basin, WyomingAcreage. As of December 31, 2018, the Company owned oil and natural gas leases totaling approximately 114,000 gross (79,000 net) acres insouthwest Wyoming’s Green River Basin. Most of this acreage covers the Pinedale and Jonah fields. Of the total acreage position in Wyoming and as ofDecember 31, 2018, approximately 41,000 gross (27,000 net) acres were developed, and 73,000 gross (52,000 net) acres were undeveloped. The developedand undeveloped portion represents 100% of the Company’s total developed and undeveloped net acreage. The Company operates 89% of its acreageposition in the Pinedale field and 89% of its production.Lease maintenance costs in Wyoming were approximately $1.0 million for the year ended December 31, 2018. The Company currently owns 68 leasestotaling 80,000 gross (54,000 net) acres that are held by production and activities (“HBP”). The HBP acreage includes all of the Company’s leases within theproductive area of the Pinedale and Jonah fields.Development Wells. Development wells are wells that were drilled in the current year that were proved undeveloped locations in the prior year’sreserve report. During 2018, the Company participated in the drilling of 107.0 gross (80.7 net) productive development wells on the Green River Basinproperties, of which 102.0 gross (77.1 net) productive development wells were vertical and 5.0 gross (3.6 net) productive development wells werehorizontal. At December 31, 2018, there were 9.0 gross (6.6 net) additional development wells that commenced during the year and were either still drillingor had operations suspended at a depth short of total depth.Exploratory Wells. Exploratory wells are wells that were drilled in the current year that were not proved undeveloped locations in the prior year’sreserve report. During 2018, the Company participated in the drilling of a total of 28.0 gross (19.8 net) productive exploratory wells on the Green RiverBasin properties, of which 14.0 gross (9.0 net) productive exploratory wells were vertical and 14.0 gross (10.8 net) productive exploratory wells werehorizontal. At December 31, 2018, there were 11.0 gross (5.1 net) additional exploratory wells that commenced during the year that were either still drillingor had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year-end.Seismic Activity. The Company owns 492 square miles of 3D seismic data in Wyoming which, when overlap is subtracted, covers 415 square miles.The data consists of both proprietary data and data licensed from independent seismic contractors and provides coverage over the entire productive areas ofPinedale and Jonah fields. During 2016, the Company completed a project to merge the various data sets and reprocess the entire volume.Divested AssetsUinta Basin, Utah. During the third quarter 2018, the Company sold the oil and gas properties covering approximately 8,300 gross (7,800 net) acres inthe Uinta Basin in Utah for net cash proceeds of $69.3 million, including management fees of $0.6 million. This acreage is located in Uintah County in theeastern portion of the Uinta Basin.Lease maintenance costs in Utah for the year ended December 31, 2018 were not significant.The Company did not participate in the drilling of any development or exploratory wells on the Utah properties during 2018.Pennsylvania. During the fourth quarter of 2017, the Company sold the oil and gas leases covering 144,000 gross (72,000 net) acres in the Pennsylvaniaportion of the Appalachian Basin for a cash purchase price of approximately $115.0 million.27Table of Contents Oil and Gas ReservesThe following table sets forth the Company’s quantities of proved reserves for the years ended December 31, 2018, 2017 and 2016. The tablesummarizes the Company’s proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cashflows attributable thereto at December 31, 2018, 2017 and 2016. In 2017, the Company renegotiated its existing gas processing contracts in Wyoming. Thesegas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include theNGL volumes in its reserves. Prior to this time, the Company’s contracts provided for the election to process NGLs. As of December 31, 2018 and 2017,proved undeveloped reserves represented 23% of the Company’s total proved reserves. The Company did not record any proved undeveloped reserves forthe year ended December 31, 2016 because of the going concern assessment at period end. December 31, 2018 2017 2016 ($ amounts in thousands, except per unit data) Proved Developed Reserves Natural gas (MMcf) 2,243,956 2,261,289 2,321,613 Oil (MBbl) 17,876 21,652 21,475 Natural gas liquids (MBbl) — 71 9,903 Proved Undeveloped Reserves Natural gas (MMcf) 677,877 694,703 — Oil (MBbl) 5,569 5,466 — Natural gas liquids (MBbl) — — — Total Proved Reserves (MMcfe) (1) 3,062,503 3,119,126 2,509,881 Estimated future net cash flows, before income tax $4,724,843 $4,377,344 $2,791,229 Standardized measure of discounted future net cash flows, before income taxes (2) $2,585,540 $2,384,328 $1,690,946 Future income tax $(180,057) $— $— Standardized measure of discounted future net cash flows, after income tax $2,405,483 $2,384,328 $1,690,946 Calculated average price (3) Gas ($/Mcf) $2.59 $2.59 $2.07 Oil ($/Bbl) $63.49 $48.05 $37.90 NGLs ($/Bbl) $— $26.85 $19.17 (1)Oil, condensate and NGLs are converted to natural gas at the ratio of one barrel of liquids to six Mcf of natural gas. This conversion ratio, which istypically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas.(2)Management believes that the presentation of the standardized measure of discounted future net cash flows, before income taxes, of estimated provedreserves, discounted at 10% per annum, may be considered a non-Generally Accepted Accounting Principle financial measure as defined in Item 10(e)of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable Generally AcceptedAccounting Principle (“GAAP”) financial measure (standardized measure of discounted future net cash flows, after income taxes). Managementbelieves that the presentation of the standardized measure of future net cash flows before income taxes provides useful information to investors becauseit is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique toeach individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability whenevaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of the Company’s oil and natural gasproperties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to othercompanies. The standardized measure of discounted future net cash flows, before income taxes, is not a measure of financial or operating performanceunder GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. Standardizedmeasure of discounted future net cash flows, before income taxes, should not be considered in isolation or as a substitute for the standardized measureof discounted future net cash flows as defined under GAAP.(3)As prescribed by SEC rules, our reserve estimates at December 31, 2018, 2017 and 2016, reflect prices based on the average of the monthly pricesduring the 12-month period before the ending date of the period covered by this report determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period.Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority oragency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve andother information, with the EIA.28Table of Contents Proved Undeveloped ReservesChanges in proved undeveloped reserves: Changes to the Company’s proved undeveloped reserves (“PUDs”) during 2018 are summarized in thetable below. These changes include updates to prior PUDs, the addition of new PUDs associated with the current development plans, the transfer of PUDs tounproved categories due to development plan changes, and the impact of changes in economic conditions, including changes in commodity prices. TheCompany’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years. The Companyannually reviews all PUDs to ensure an appropriate plan for development exists. As of December 31, 2018, 100% of the proved undeveloped locations arelocated in Wyoming. MMcfe Proved undeveloped reserves, December 31, 2017 727,499 Converted to proved developed (322,024)Proved undeveloped reserve extensions 40,472 Proved undeveloped reserves purchased — Proved undeveloped reserve revisions 265,346 Proved undeveloped reserves, December 31, 2018 711,293 Conversions: In 2018, the conversion rate was 44.3% based on PUDs recorded as of December 31, 2018.Additions/Extensions: In 2018, the Company’s reserve additions were comprised of Pinedale drilling locations that moved into the five-year provedundeveloped window. These locations have never been previously classified as proved undeveloped.Purchases: In 2018, there were no purchases related to PUD reserves.Revisions: In 2018, price and performance revisions, along with the transfers of previously booked PUD locations, are included in the reportedrevisions.Internal Controls Over Reserve Estimating ProcessOur policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gasreserve quantities and present values in compliance with the SEC’s regulations and GAAP. Our Director of Reservoir and Development is primarilyresponsible for overseeing the preparation of the Company’s reserve estimates and has a Bachelor of Science degree in Petroleum Engineering with over 14years of experience.The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review ofassumptions used in the estimation as well as ultimate approval of our capital budget and review of our development plan by our senior management andBoard of Directors. The development plan underlying the Company’s PUD reserves, if any, is further subject to internal controls, including a comparison offuture development costs to historical expenditures as well as our future development plan and financial capabilities, and an evaluation of the estimatedprofitability of each location at the time the report is prepared. The development plan underlying the Company’s proved undeveloped reserves, adoptedevery year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs,performance data, and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions includedeferrals, removals, and substitutions of previously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizingprofitability and are in the best interest of the Company’s shareholders.The estimates of proved reserves and future net revenue as of December 31, 2018 are based upon the use of technical and economic data including, butnot limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering andevaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy,that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules andregulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering andgeoscience data; therefore, these estimates necessarily represent only informed professional judgment.The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates forall of the Company’s assets for the years ended December 31, 2018, 2017 and 2016 in this annual report.29Table of Contents Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserveestimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performancedata, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the externalengineers as part of their evaluation of our reserves. The report of NSAI is included as Exhibit 99.1 to this annual report.The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry andfinancial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board ofProfessional Engineers Registration No. F 2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAIreserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No.125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over seven years of prior industry experience. He graduated fromUniversity of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State ofTexas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduatedfrom University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree inGeophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to theEstimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciouslyapplying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions andguidelines.30Table of Contents Production Volumes, Average Sales Prices and Average Production CostsThe following table sets forth certain information regarding the production volumes and average sales prices received for and average production costsassociated with the Company’s sale of oil and natural gas for the periods indicated. Year ended December 31, 2018 2017 2016 (In thousands, except per unit data) Production Natural gas (Mcf) 260,406 260,009 264,278 Oil (Bbl) 2,442 2,775 2,912 Total (Mcfe) 275,058 276,659 281,748 Revenues Natural gas sales $722,313 $748,682 $609,756 Oil sales 153,534 133,368 111,335 Other revenues 16,652 9,823 — Total revenues $892,499 $891,873 $721,091 Lease Operating Expenses Lease operating expenses (1) $90,290 $92,326 $89,134 Facility lease expense 25,947 21,749 20,686 Severance/production taxes 93,322 91,067 69,737 Gathering 89,806 86,953 86,809 Total lease operating expenses $299,365 $292,095 $266,366 Average Realized Prices Natural gas ($/Mcf, including realized gains (losses) on commodityderivatives) $2.48 $2.92 $2.31 Natural gas ($/Mcf, excluding realized gains (losses) on commodityderivatives) $2.77 $2.88 $2.31 Oil ($/Bbl), including realized gains (losses) on commodity derivatives) $59.44 $48.05 $38.24 Oil ($/Bbl), excluding realized gains (losses) on commodity derivatives) $62.88 $48.05 $38.24 Average Costs per Mcfe Lease operating expenses $0.33 $0.33 $0.32 Facility lease expense $0.09 $0.08 $0.07 Severance/production taxes $0.34 $0.33 $0.25 Gathering $0.33 $0.31 $0.31 Transportation charges $— $— $0.07 DD&A $0.74 $0.59 $0.44 General & administrative $0.09 $0.14 $0.03 Interest $0.54 $1.31 $0.24 Total costs per Mcfe $2.46 $3.09 $1.73 (1)Lease operating costs include lifting costs and remedial workover expenses. The following table sets forth the net sales volumes, operating expenses and average realized natural gas prices attributable to the Pinedale field, whichis the only field that contained 15% or more of our total estimated proved reserves as of December 31, 2018: Year ended December 31, 2018 2017 2016 (In thousands) Pinedale Field: Production (Mcfe) 264,786 256,695 256,881 Operating expenses $282,376 $265,051 $241,975 Average realized price ($/Mcf excluding realized gains (losses) on commodityderivatives) $2.78 $2.90 $2.35 Average realized price ($/Mcf including realized gains (losses) on commodityderivatives) $2.48 $2.95 $2.3531Table of Contents Delivery CommitmentsWith respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas toits customers. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all ofthese commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities orcurtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agenciesor any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Part I. Item 1A.“Risk Factors.” If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchasevolumes in the market or make other arrangements to satisfy the commitments.Productive WellsAs of December 31, 2018, the Company’s total gross and net wells were as follows: Gross Wells Net Wells Productive Wells* Operated 2,204 1,882 Operated by others 836 234 Total productive wells 3,040 2,116 *Productive wells are producing wells, shut-in wells the Company deems capable of production, wells that are waiting for completion, plus wells that aredrilled/cased and completed, but waiting for pipeline hook-up. A gross well is a well in which a working interest is owned. The number of net wellsrepresents the sum of fractional working interests the company owns in gross wells.Oil and Gas AcreageThe primary terms of the Company’s oil and gas leases expire at various dates. Much of the Company’s undeveloped acreage is held by production,which means that the Company will maintain its rights in these leases as long as oil or natural gas is produced from the acreage by it or by other partiesholding interests in producing wells on those leases. In some cases, if production from a lease ceases, the lease will expire, and in some cases, if productionfrom a lease ceases, the Company may maintain the lease by additional operations on the acreage.The Company does not believe the risk of remaining terms of its leases are material. The Company expects to maintain essentially all the materialleases among its oil and gas properties by production, operations, extensions or renewals. The Company does not expect to lose material lease acreagebecause of failure to drill due to inadequate capital, equipment or personnel. The Company has, based on its evaluation of prospective economics, allowedacreage to expire and it may allow additional acreage to expire in the future. As of December 31, 2018, the Company does not anticipate any Wyomingleased acres to expire in 2019 and estimates that approximately 8,200 net leased acres in Wyoming may expire in 2020 and beyond.As of December 31, 2018, the Company had total gross and net developed and undeveloped oil and natural gas leasehold acres in the United States asset forth below. Developed Acres Undeveloped Acres Gross Net Gross Net Wyoming 41,000 27,000 73,000 52,000 Drilling ActivitiesFor each of the three fiscal years ended December 31, 2018, 2017 and 2016, the number of gross and net wells drilled by the Company was as follows:Wyoming — Green River Basin 2018 2017 2016 Gross Net Gross Net Gross Net Development Wells Productive 107.0 80.7 — — — — Dry — — — — — — Total 107.0 80.7 — — — — 32Table of Contents At December 31, 2018, there were 9.0 gross (6.6 net) additional development wells that were either drilling or had operations suspended. This includeswells in the Pinedale field. 2018 2017 2016 Gross Net Gross Net Gross Net Exploratory Wells Productive 28.0 19.8 210.0 172.1 94.0 68.6 Dry — — — — — — Total 28.0 19.8 210.0 172.1 94.0 68.6 At December 31, 2018, there were 11.0 gross (5.1 net) additional exploratory wells that were either drilling or had operations suspended in the Pinedalefield.UtahThe Company divested its Utah assets during the third quarter of 2018. For the years ended December 31, 2018, 2017 and 2016, the Company did notdrill any development or exploratory wells on its Utah acreage.PennsylvaniaThe Company divested its Pennsylvania assets during the fourth quarter of 2017. For the years ended December 31, 2017 and 2016, the Company didnot drill any development or exploratory wells on its Pennsylvania acreage. ColoradoThe Company did not conduct any operations on this acreage during 2018, 2017 or 2016. In 2014, the Company sold the surface rights to its Coloradoundeveloped acreage and retained some oil and gas (mineral) rights. The Company no longer owns any leased acreage in Colorado and has no immediateplans for further exploration in Colorado during 2019.Item 3.Legal Proceedings.See Note 12 for discussion of on-going claims and disputes that arose during our chapter 11 proceedings, certain of which may be material. TheCompany is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine orpredict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have amaterial adverse effect on the Company’s financial position, or results of operations.Item 4. Mine Safety Disclosures.None. 33Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.The Company’s common shares are traded on the NASDAQ (the “NASDAQ”) under the symbol “UPL”. As of February 28, 2019, there were approximately 329 holders of record of the common shares.Dividends The Company has not declared or paid and does not anticipate declaring or paying any dividends on its common shares in the nearfuture. Additionally, our Credit Agreement (defined below), Term Loan Agreement (defined below), and the indentures governing the Second Lien Notes(defined below) place certain restrictions on our ability to pay cash dividends. The Company intends to retain its cash flow from operations for the futureoperation and development of its oil and gas properties.Performance GraphThe following share price performance graph is intended to allow review of shareholder returns, expressed in terms of the appreciation of theCompany’s common shares relative to two broad-based stock performance indices. The information is included for historical comparative purposes only andshould not be considered indicative of future share performance. The graph below matches the Company’s cumulative total shareholder return on commonstock since the date of the Company’s emergence from chapter 11 proceedings with the cumulative total returns of the NYSE Composite index and the DowJones US Exploration and Production TSM index. The graph tracks quarterly performance of a $100 investment in our common stock and each respectiveindex (with the reinvestment of all dividends) from the April 13, 2017 through December 31, 2018. 34Table of Contents Unregistered Sales of Equity Securities On December 21, 2018, the Company completed the Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) $505 millionaggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principal amount, or 55.0%, of the issuedand outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes of Ultra Resources and (b) an aggregate of 10,919,499Warrants of the Company. See to Item 7. “Management’s Discussion and Analysis”, for additional details regarding the Exchange Transaction. Each Warrant is initially exercisable for one common share of the Company at an initial exercise price of $0.01 per Warrant (the “Exercise Price”). NoWarrants will be exercisable until the date on which the volume-weighted average price of the Company’s common shares is at least $2.50 per common sharefor 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of theholders thereof from December 21, 2018 until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holders of such Warrantsto purchase common shares will terminate. The Warrants issued in the Exchange Transaction were offered and sold pursuant to the exemption provided by Section 4(a)(2) of the Securities Act.This offer was made by the Company to a limited number of persons, each of which is an accredited investor (within the meaning of Rule 501 promulgatedunder the Securities Act).35Table of Contents Item 6. Selected Financial Data.The selected consolidated financial information presented below for the years ended December 31, 2018, 2017, 2016, 2015 and 2014 is derived fromthe Consolidated Financial Statements of the Company. Year Ended December 31, 2018 2017 2016 2015 2014 (In thousands, except per share data) Statement of Operations Data: Revenues: Natural gas sales $722,313 $748,682 $609,756 $696,730 $969,850 Oil sales 153,534 133,368 111,335 142,381 260,170 Other revenues 16,652 9,823 — — — Total operating revenues 892,499 891,873 721,091 839,111 1,230,020 Expenses: Production expenses and taxes 299,365 292,095 266,366 288,231 280,631 Transportation charges — — 20,049 83,803 77,780 Depletion, depreciation and amortization 204,255 161,945 125,121 401,200 292,951 Ceiling test and other impairments — — — 3,144,899 — General and administrative 25,005 39,548 9,179 7,387 19,069 Other expenses 9,118 — — — — Total operating expenses 537,743 493,588 420,715 3,925,520 670,431 Other: Interest expense (148,316) (361,367) (66,565) (171,918) (126,157)Gain (loss) on commodity derivatives (145,212) 28,412 — 42,611 82,402 Deferred gain on sale of liquids gathering system 10,553 10,553 10,553 10,553 10,553 Contract settlement income (expense), net 12,656 (52,707) (131,106) — — Gain on sale of property — — — — 8,022 Litigation expense — — — (4,401) — Restructuring expenses — — (7,176) — — Reorganization items, net — 140,907 (47,503) — — Other (expense) income, net 1,212 (237) (3,082) (2,060) 2,618 Total other income (expense), net (269,107) (234,439) (244,879) (125,215) (22,562) Income (loss) before income taxes 85,649 163,846 55,497 (3,211,624) 537,027 Income tax (benefit) 442 (13,294) (654) (4,404) (5,824) Net income (loss) $85,207 $177,140 $56,151 $(3,207,220) $542,851 Basic Earnings (Loss) per Share: Net income (loss) per common share — basic (1) $0.43 $1.08 $0.70 $(40.14) $6.79 Fully Diluted Earnings (Loss) per Share: Net income (loss) per common share — fully diluted (1) $0.43 $1.08 $0.70 $(40.14) $6.73 Statement of Cash Flows Data (2): Net cash provided by (used in): Operating activities $310,897 $65,268 $311,070 $515,536 $712,582 Investing activities $(401,710) $(435,311) $(278,900) $(512,757) $(1,600,743)Financing activities $91,849 $(16,737) $368,621 $(7,557) $886,414 Balance Sheet Data: Cash and cash equivalents $17,014 $16,631 $401,478 $4,143 $8,919 Working capital (deficit) $(52,481) $(81,065) $383,185 $(3,560,683) $(168,580)Oil and gas properties $1,497,727 $1,325,068 $1,010,466 $851,145 $3,878,937 Total assets $1,733,288 $1,512,982 $1,540,928 $952,039 $4,225,690 Total debt, net(3)(4) $2,215,481 $2,116,211 $— $3,390,000 $3,378,000 Other long-term obligations $211,895 $197,728 $177,088 $165,784 $152,472 Deferred income taxes, net $— $— $— $— $992 Total shareholders’ (deficit) equity $(1,048,622) $(1,154,636) $(2,928,151) $(2,991,937) $211,660 (1)In conjunction with emergence from chapter 11 proceedings, the Company issued new common shares to holders of existing common shares at a conversion ratio of0.521562. The earnings (loss) per share has been adjusted to reflect this conversion as if it had occurred on January 1, 2014.(2)Cash flows from operating activities for the years ended December 31, 2016, 2015 and 2014, have been updated to reflect the retrospective application of the Company’sadoption of ASU 2016-18.(3)At December 31, 2016, $2.1 billion of long-term debt is included with liabilities subject to compromise on our Consolidated Balance Sheets.(4)At December 31, 2018 and 2017, costs associated with the issuance of our long-term debt, excluding the costs associated with the Revolving Credit Facility are presented asa direct deduction from the carrying value of the related debt liability on the Consolidated Balance Sheet. 36Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto includedelsewhere in this report. Further, we encourage you to revisit the Forward-Looking Statements section in Item 1A. “Risk Factors.”Operations OverviewProduction and RevenuesUltra Petroleum Corp. is an independent exploration and production company focused on developing and producing its long-life natural gas reservesin the Pinedale and Jonah fields of the Green River Basin of southwest Wyoming. The Company operates in one industry segment, natural gas and oilexploration and development, with one geographical segment, the United States.The Company conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly withothers and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. The Company continues to focus onimproving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its propertiesand leveraging its experience. Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results ofoperations or capital investment program.The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from itsproperties in southwest Wyoming. During the year ended December 31, 2018, the Company generated revenue from oil sales from properties in the UintaBasin in Utah, which were sold during the third quarter of 2018. During 2014, the Company acquired contracts to process NGLs beginning in 2017. During 2017, the Company renegotiated its existing gas processingcontracts in Wyoming. The new gas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing andaccordingly does not include the NGL volumes in its reserves.The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and thisvolatility could be detrimental to the Company’s financial performance. As a result, and from time to time, the Company tries to limit the impact of thisvolatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas and oil. The Company isrequired under its Revolving Credit Facility to enter into derivative commodity contracts for a minimum of 65% of its forecast proven producing natural gasreserves for the ensuing 18-month period. The Company has also begun to utilize more costless collars and is now utilizing put contracts, with low premiumcosts, to provide a degree of floor price protection and allow the Company to participate in more upward price exposure. (See Note 8).The average price realization for the Company’s natural gas during 2018 was $2.48 per Mcf, including realized gains and losses on commodityderivatives. During the quarter ended December 31, 2018, the average price realization for the Company’s natural gas was $2.58 per Mcf, including realizedgains and losses on commodity derivatives. The Company’s average price realization for natural gas, excluding realized gains and losses on commodityderivatives, was $2.77 per Mcf and $3.95 per Mcf for the year and the quarter ended December 31, 2018, respectively.The average price realization for the Company’s crude oil and condensate during 2018 was $59.44 per barrel, including realized gains and losses oncommodity derivatives. During the quarter ended December 31, 2018, the average price realization for the Company’s crude oil and condensate was $61.74per barrel, including realized gains and losses on commodity derivatives. The Company’s average price realization for crude oil and condensate, excludingrealized gains and losses on commodity derivatives, was $62.88 per barrel and $58.30 per barrel for the year and the quarter ended December 31, 2018,respectively.Capital InvestmentsThe Company began 2018 with seven operated rigs running in the Pinedale field with a mix of planned activities on both vertical wells and horizontalwells. In the second quarter of 2018, the decision was made to assign all rigs to horizontal development. As the results for the horizontal development beganto come in, the decision was made to reduce the number of rigs to four operated rigs and then subsequently to pause the horizontal drilling program andconcentrate on vertical well development in Pinedale with a three operated rig program in the third quarter through the end of 2018. The total capitalinvestment in oil and gas properties was $426.2 million and resulted in a total of 116 gross (86.0 net) vertical wells and 19 gross (14.4 net) horizontal wellswhich were drilled and cased in the Pinedale field. The Company has paused its horizontal well program to evaluate the results of the program, perform additional sub-surface evaluation, and consideralternatives to its well design and completion techniques. As the Company continues to learn, it may incorporate a limited number of wells into the verticalprogram utilizing the existing three-rig fleet. The per well cost for the horizontal wells averaged $10.3 million per well in gross costs including facilities asof December 31, 2018. The vertical well costs began to come back to historical levels in the fourth quarter of 2018, where these costs averaged $3.1million. This improvement from higher levels during 2018 was a reflection of more concentrated operations and the resulting efficiencies from developmenton larger drill pads resulting in less rig movement and a higher utilization rate of equipment as a result.37Table of Contents Liquidity and Working CapitalAs of December 31, 2018, the Company had $17.0 million of cash and $104.0 million outstanding under its Revolving Credit Facility. The RevolvingCredit Facility has availability up to $325.0 million, providing the Company $221.0 million of additional liquidity as of the end of the 2018. Subsequent toyear-end, the Company reaffirmed it borrowing base at $1.3 million and entered into an amendment of its Revolving Credit Facility.Working capital can be impacted by changes in the timing of receivables and payables. A significant item that impacted working capital as ofDecember 31, 2018, was related to the timing of derivative settlements. A significant portion of our derivative settlements relate to fixed price natural gasand fixed price basis. The derivative settlements in the fourth quarter of 2018 were significant and also impacted our working capital. The timing ofsettlements for natural gas fixed price and basis is determined on the first of month pricing in the month of production. The natural gas basis settlementprices for December were significantly higher than the derivative contract price for that period. As a result, the settlement of the December 2018 derivativecontracts for natural gas was $34.1 million and basis was $30.8 million and required a utilization of that amount in working capital and as borrowings underour Revolving Credit Facility. Conversely, the physical sales value for December 2018 of natural gas were accrued at the higher first of month price for asubstantial portion of our December 2018 production and this amount was accrued as of December 31, 2018 as a receivable. The timing for collection of thereceivable is approximately the 25th day of the month after the month of sale, resulting in an approximate 50-55 day lag in the matching of the cash flowsbetween the settlement of the derivative contract and the physical sales. This can have a significant impact on month-to-month working capital. All amountshave been collected under the physical sales contracts and the utilization under the Revolving Credit Facility has been reduced subsequent to December 31,2018.As of February 28, 2019, the Company had a cash balance of approximately $6 million and $41 million due under the Revolving Credit Facility.2018 Debt Exchange TransactionIn December 2018, the Company completed the Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) $505.0 millionaggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275.0 million aggregate principal amount, or 55.0%, of the issuedand outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Senior Secured Second Lien Notes due July 2024 and (b) an aggregate of10,919,499 new warrants of the Company each entitling the holder thereof to purchase one common share of the Company. This transaction resulted in areduction of total principal indebtedness by approximately $235.0 million in December 2018. The Company evaluated the accounting treatment of theExchange Transaction under ASC 470, Debt. Subsequent to year-end, the Company has continued to execute follow-on exchanges of its 2022 Notes for Second Lien Notes, as allowed by theSecond Lien Notes Indenture. Under the Second Lien Notes Indenture, the Company is permitted to exchange up to $55 million of 2022 Notes for SecondLien Notes at terms that are at or more favorable to the Company than the terms of the Exchange Transaction. Through February 28, 2019, the Company hasexchanged an additional $44.6 million of 2022 Notes for approximately $27.0 million of Second Lien Notes, bringing the total reductions to debt from theseexchanges to $252.5 million, inclusive of the Exchange Transaction. The Company will evaluate the treatment of the follow-on exchanges under the sameaccounting literature used in the Exchange Transaction. The Company continues to retain the ability under the Second Lien Notes Indenture to furtherexchange $10.4 million of the remaining 2022 Notes within one-year of the Exchange Transaction. 2017 Chapter 11 ProceedingsThe Company emerged from chapter 11 proceedings during the year ended, December 31, 2017. The effects of the Plan (defined below) were includedin the Consolidated Financial Statements as of December 31, 2017, and the related adjustments thereto were recorded in our Consolidated Statement ofOperations as reorganization items for the twelve months ended December 31, 2017.Voluntary Reorganization Under Chapter 11On April 29, 2016, the Company and its subsidiaries (collectively, “the Debtors”) filed voluntary petitions under chapter 11 of title 11 of the UnitedStates Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointlyadministered under the caption In re Ultra Petroleum Corp., et al, (Case No. 16-32202 (MI). On March 14, 2017, the Bankruptcy Court confirmed ourDebtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”) and on April 12, 2017 (the “Effective Date”), we emerged from bankruptcy.See Note 14 in the Notes to the Consolidated Financial Statements for further discussion of these matters.Fresh Start AccountingWe were not required to apply fresh start accounting to our consolidated financial statements in connection with our emergence from bankruptcybecause the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowedclaims.38Table of Contents Results of Operations — Year Ended December 31, 2018 vs. Year Ended December 31, 2017 For the year ended December 31, 2018 2017 % change (Amounts in thousands,except per unit data) Production, Commodity Prices and Revenues: Production: Natural gas (Mcf) 260,406 260,009 0%Crude oil and condensate (Bbls) 2,442 2,775 -12%Total production (Mcfe) 275,058 276,659 -1% Commodity Prices: Natural gas ($/Mcf, incl realized hedges) $2.48 $2.92 -15%Natural gas ($/Mcf, excluding hedges) $2.77 $2.88 -4%Crude oil and condensate ($/Bbl, incl realized hedges) $59.44 $48.05 24%Crude oil and condensate ($/Bbl, excluding hedges) $62.88 $48.05 31% Revenues: Natural gas sales $722,313 $748,682 -4%Oil sales $153,534 $133,368 15%Other revenues $16,652 $9,823 70%Total operating revenues $892,499 $891,873 0% Derivatives: Realized gain (loss) on commodity derivatives $(85,413) $11,446 -846%Unrealized gain (loss) on commodity derivatives $(59,799) $16,966 -452%Total gain (loss) on commodity derivatives $(145,212) $28,412 -611% Operating Costs and Expenses: Lease operating expenses $90,290 $92,326 -2%Facility lease expense $25,947 $21,749 19%Production taxes $93,322 $91,067 2%Gathering fees $89,806 $86,953 3%Depletion, depreciation and amortization $204,255 $161,945 26%General and administrative expenses $25,005 $39,548 -37% Per Unit Costs and Expenses ($/Mcfe): Lease operating expenses $0.33 $0.33 0%Facility lease expense $0.09 $0.08 13%Production taxes $0.34 $0.33 3%Gathering fees $0.33 $0.31 6%Depletion, depreciation and amortization $0.74 $0.59 25%General and administrative expenses $0.09 $0.14 -36% Production, Commodity Prices and Revenues:Production. During the year ended December 31, 2018, production slightly decreased on a gas equivalent basis to 275.1 Bcfe from 276.7 Bcfe for thesame period in 2017. The decrease is primarily attributable to the sale of the non-core, predominately natural gas, assets in Pennsylvania during the fourthquarter of 2017 and non-core, predominately oil, assets in Utah during the third quarter of 2018.Revenues. During the year ended December 31, 2018, revenues slightly increased to $892.5 million for the year ended December 31, 2018, ascompared to $891.9 million in 2017. This increase is attributable to the increase in average oil prices, partially offset by the decrease in natural gas prices.39Table of Contents Commodity prices — natural gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased to $2.48 perMcf during the year ended December 31, 2018 as compared to $2.92 per Mcf during 2017. This net realized price is a combination of the natural gas prices atHenry Hub and inclusive of our basis differentials at NwRox. The Company has open natural gas price commodity derivative contracts as of December 31,2018. See Note 8 for additional details relating to these derivative contracts. During the year ended December 31, 2018, the Company’s average price fornatural gas, excluding realized gains and losses on commodity derivatives, was $2.77 per Mcf as compared to $2.88 per Mcf for the same period in 2017. Therealized price during the year was fairly consistent; however, in the fourth quarter of 2018 the realized price for physical gas sales increased as a result of apipeline outage supplying natural gas from Canada, among other things. Trades indicate that the basis differentials for the forward-looking basis market for2019 and 2020 are negative to Henry Hub by approximately $0.30 and $0.46, respectively, highlighting potential volatility that can occur in our natural gaspricing.Commodity prices — oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased to $59.44 per barrel during theyear ended December 31, 2018, as compared to $48.05 per barrel during 2017. The Company has open oil price commodity derivative contracts as ofDecember 31, 2018. During the year ended December 31, 2018, the Company’s average price for oil, excluding realized gains and losses on commodityderivatives, was $62.88 per barrel compared to $48.05 per barrel for the same period in 2017.Operating Costs and Expenses:Lease Operating Expense. Lease operating expenses (“LOE”) decreased slightly to $90.3 million for the year ended December 31, 2018 compared to$92.3 million during the same period in 2017 due to a slight decrease in the overall well count which was a result of the Utah divesture in September 2018.While production from the Utah assets was minimal to the overall consolidated results, the Utah assets predominately produced oil and the LOE averaged$2.63 per Mcfe prior to the divesture. On a unit of production basis, consolidated LOE costs remained flat at $0.33 per Mcfe at December 31, 2018 and 2017.Facility Lease Expense. In 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “Pinedale LGS”) andcertain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with thebuyer relating to the use of the Pinedale LGS (the “Pinedale Lease Agreement”). For the year ended December 31, 2018, the Company recognized operatinglease expense associated with the Pinedale Lease Agreement of $25.9 million, or $0.09 per Mcfe compared with $21.7 million, or $0.08 per Mcfe in 2017.This increase is a result of exceeding certain volume thresholds set forth in the original Pinedale Lease Agreement.Production Taxes. During the year ended December 31, 2018, production taxes were $93.3 million compared to $91.1 million during the same periodin 2017, or $0.34 per Mcfe in 2018, compared to $0.33 per Mcfe in 2017. Production taxes are primarily calculated based on a percentage of revenue fromproduction in Wyoming after certain deductions and were 10.5% of revenues for the year ended 2018 and 10.2% for the same period in 2017. The increase inproduction taxes is primarily attributable to increased oil prices during the year December 31, 2018 as compared to the same period in 2017.Gathering Fees. Gathering fees increased slightly to $89.8 million for the year ended December 31, 2018 compared to $87.0 million during the sameperiod in 2017. This slight increase was mainly attributable to the higher costs incurred for trucking fees when disruptions on the oil pipeline occurred duringthe first half of 2018. On a per unit basis, gathering fees were $0.33 per Mcfe for the year ended December 31, 2018 as compared to $0.31 per Mcfe atDecember 31, 2017. Gathering fees during the second half of 2018 averaged $0.32 per Mcfe.Depletion, Depreciation and Amortization. DD&A expenses increased to $204.3 million during the year ended December 31, 2018 from$161.9 million for the same period in 2017, attributable to the addition of proved undeveloped reserves and the associated capital as a result of theCompany’s emergence from chapter 11 proceedings in April 2017. On a unit of production basis, DD&A increased to $0.74 per Mcfe at December 31, 2018from $0.59 per Mcfe at December 31, 2017.General and Administrative Expenses. General and administrative expenses decreased to $25.0 million for the year ended December 31, 2018compared to $39.5 million for the same period in 2017. The decrease in general and administrative expenses is primarily attributable to the stock incentivecompensation expense that was incurred for the year ended December 31, 2017 as part of the 2017 Stock Incentive Plan. For the years ended December 31,2018 and 2017, the Company recognized $10.9 million and $38.5 million, respectively, of pre-tax compensation expense related to the Initial MIP Grants asdescribed in Note 7. On a per unit basis, general and administrative expenses decreased to $0.09 per Mcfe at December 31, 2018 from $0.14 per Mcfe atDecember 31, 2017.Other Expenses. The Company recognized $9.1 million of other expenses for the year ended December 31, 2018, of which $4.9 million is attributableto the provision for uncollectible accounts and $4.2 million is attributable to the Houston office relocation. There were no other expenses incurred duringthe year ended December 31, 2017.Other Income and Expenses:Interest Expense. Interest expense decreased to $148.3 million during the year ended December 31, 2018 compared to $361.4 million during thesame period in 2017. The decrease in interest expense is primarily attributable to the postpetition interest of $175.2 million recognized in 2017, related to theBankruptcy Court order denying our objection to post-petition interest claims, at the default rate for the period beginning April 29, 2016 through April 12,2017. Subsequent to December 31, 2018, the U.S. Court of Appeals for the Fifth Circuit issued an opinion vacating the order of the Bankruptcy Courtdenying our objection to the asserted make-whole and post-petition interest claims, and remanding the matter and those determinations to the BankruptcyCourt for further reconsideration. Refer to Note 15 for additional details regarding this appeal.40Table of Contents Contract Settlement Income (Expense), Net. The Company recognized $12.7 million of net contract settlement income for the year endedDecember 31, 2018 compared to $52.7 million of contract settlement expense for the year ended December 31, 2017. In the fourth quarter of 2018, theCompany entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company.Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company. This was partiallyoffset by fees associated with completing the Settlement Agreements. The Company will continue to pursue its appeal against all non-settled parties. In 2017,the Company reached a contract settlement of $57.0 million for a 2016 claim related to a transportation contract.Deferred Gain on Sale of Liquids Gathering System. During the years ended December 31, 2018 and 2017, the Company recognized $10.6 million indeferred gain on sale of the liquids gathering system relating to the sale of the Pinedale LGS in 2012.Commodity Derivatives:Gain (Loss) on Commodity Derivatives. During the year ended December 31, 2018, the Company recognized a loss of $145.2 million related tocommodity derivatives. Of this total, the Company recognized $85.4 million related to realized loss during the year ended December 31, 2018. The realizedgain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain or loss on commodityderivatives also includes a $59.8 million unrealized loss on commodity derivatives at December 31, 2018. The unrealized gain or loss on commodityderivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract. Reorganization Items:Reorganization Items, Net. Reorganization items, net were $140.9 million as of December 31, 2017 and was primarily consisted of expenses of $66.3million in professional fees associated with the Company’s chapter 11 cases and $223.8 million related to the Bankruptcy Court order denying our objectionto the make-whole claims offset by a gain of $431.1 million, which primarily represents the gain on the debt for equity exchange related to the Company’sprepetition senior notes. Income from Operations:Pretax Income. The Company recognized income before income taxes of $85.6 million for the year ended December 31, 2018 compared with incomeof $163.8 million for the same period in 2017. The decrease in earnings is primarily attributable to the loss recognized on the commodity derivatives as ofDecember 31, 2018 compared to a gain that was recognized in the same period of 2017, and partially offset by the decrease in interest expense.Income Taxes. The Company has recorded a $0.4 million tax expense for the year ended December 31, 2018 associated with the finalization ofcertain items from earlier periods. The Company has recorded a valuation allowance against all of its net deferred tax asset balance as of December 31, 2018.Some or all of this valuation allowance may be reversed in future periods against future income.Net Income. For the year ended December 31, 2018, the Company recognized net income of $85.2 million or $0.43 per diluted share as comparedwith net income of $177.1 million or $1.08 per diluted share for the same period in 2017. The operating income and operating expense elements togetherwith the loss on commodity derivatives, offset by the decreased interest expense were the primary elements for the decrease in earnings in 2018 as comparedto 2017.41Table of Contents Results of Operations — Year Ended December 31, 2017 vs. Year Ended December 31, 2016 For the year ended December 31, 2017 2016 % change (Amounts in thousands,except per unit data) Production, Commodity Prices and Revenues: Production: Natural gas (Mcf) 260,009 264,278 -2%Crude oil and condensate (Bbls) 2,775 2,912 -5%Total production (Mcfe) 276,659 281,748 -2% Commodity Prices: Natural gas ($/Mcf, incl realized hedges) $2.92 $2.31 27%Natural gas ($/Mcf, excluding hedges) $2.88 $2.31 25%Crude oil and condensate ($/Bbl, incl realized hedges) $48.05 $38.24 26%Crude oil and condensate ($/Bbl, excluding hedges) $48.05 $38.24 26% Revenues: Natural gas sales $748,682 $609,756 23%Oil sales $133,368 $111,335 20%Other revenue $9,823 $— 100%Total operating revenues $891,873 $721,091 24% Derivatives: Realized gain on commodity derivatives $11,446 $— 100%Unrealized gain on commodity derivatives $16,966 $— 100%Total gain on commodity derivatives $28,412 $— 100% Operating Costs and Expenses: Lease operating expenses $92,326 $89,134 4%Facility lease expense $21,749 $20,686 5%Production taxes $91,067 $69,737 31%Gathering fees $86,953 $86,809 0%Transportation charges $— $20,049 -100%Depletion, depreciation and amortization $161,945 $125,121 29%General and administrative expenses $39,548 $9,179 331% Per Unit Costs and Expenses ($/Mcfe): Lease operating expenses $0.33 $0.32 3%Facility lease expense $0.08 $0.07 14%Production taxes $0.33 $0.25 32%Gathering fees $0.31 $0.31 0%Transportation charges $— $0.07 -100%Depletion, depreciation and amortization $0.59 $0.44 34%General and administrative expenses $0.14 $0.03 367% Production, Commodity Prices and Revenues:Production. During the year ended December 31, 2017, production decreased on a gas equivalent basis to 276.7 Bcfe from 281.7 Bcfe for the sameperiod in 2016. The decrease is primarily attributable to decreased capital investment during the year ended December 31, 2016.Commodity prices — natural gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased to $2.92 perMcf during the year ended December 31, 2017 as compared to $2.31 per Mcf during 2016. The Company had open derivative contracts for natural gasproduction during 2017. During the year ended December 31, 2017, the Company’s average price for natural gas excluding realized gains and losses oncommodity derivatives was $2.88 per Mcf as compared to $2.31 per Mcf for the same period in 2016.42Table of Contents Commodity prices — oil. During the year ended December 31, 2017, the average price realization for the Company’s oil was $48.05 per barrelcompared with $38.24 per barrel during 2016. The Company did not have any open derivative contracts for oil production during 2017 or 2016.Revenues. The increase in average oil and natural gas prices partially offset by decreased total production resulted in revenues increasing to $891.9million for the year ended December 31, 2017 as compared to $721.1 million in 2016.Operating Costs and Expenses:Lease Operating Expense. LOE increased to $92.3 million for the year ended December 31, 2017 compared to $89.1 million during the same periodin 2016 largely related to the increase in producing well counts. On a unit of production basis, LOE costs increased to $0.33 per Mcfe at December 31, 2017compared to $0.32 per Mcfe at December 31, 2016.Facility Lease Expense. For the year ended December 31, 2017, the Company recognized operating lease expense associated with the PinedaleLease Agreement of $21.7 million, or $0.08 per Mcfe compared with $20.7 million, or $0.07 per Mcfe in 2016.Production Taxes. During the year ended December 31, 2017, production taxes were $91.1 million compared to $69.7 million during the same periodin 2016, or $0.33 per Mcfe in 2017, compared to $0.25 per Mcfe in 2016. Production taxes are primarily calculated based on a percentage of revenue fromproduction in Wyoming and Utah after certain deductions and were 10.2% of revenues for the year ended 2017 and 9.7% for the same period in 2016. Theincrease in production taxes is primarily attributable to increased oil and natural gas prices during the year December 31, 2017, and the higher relativecontribution of Wyoming production in 2017 than as compared to the same period in 2016.Gathering Fees. Gathering fees increased slightly to $87.0 million for the year ended December 31, 2017 compared to $86.8 million during the sameperiod in 2016. On a per unit basis, gathering fees remained flat at $0.31 per Mcfe for the years ended December 31, 2017 and 2016.Transportation Charges. As a result of the termination of our contract with Rockies Express Pipeline LLC (“REX”) during the first quarter of 2016,there were no material transportation charges for the year ended December 31, 2017. Transportation charges were $20.0 million for the year endedDecember 31, 2016. Depletion, Depreciation and Amortization. DD&A expenses increased to $161.9 million during the year ended December 31, 2017 from $125.1million for the same period in 2016, attributable to the addition of “PUDs” as a result of the Company’s emergence from chapter 11 proceedings in April2017. On a unit of production basis, DD&A increased to $0.59 per Mcfe at December 31, 2017 from $0.44 per Mcfe at December 31, 2016.General and Administrative Expenses. General and administrative expenses increased to $39.5 million for the year ended December 31, 2017compared to $9.2 million for the same period in 2016. The increase in general and administrative expenses is primarily attributable to the non-cash stockincentive compensation expense that was incurred as part of the Ultra Petroleum Corp. 2017 Stock Incentive Plan, in which tranche one became fully vestedon the Effective Date. On a per unit basis, general and administrative expenses increased to $0.14 per Mcfe at December 31, 2017 from $0.03 per Mcfe atDecember 31, 2016.Other Income and Expenses:Interest Expense. Interest expense increased to $361.4 million during the year ended December 31, 2017 compared to $66.6 million during the sameperiod in 2016. The change in interest expense is comprised of $85.8 million of accrued postpetition interest for the period beginning April 29, 2016through April 12, 2017, $100.4 million of interest expense incurred on the Revolving Credit Facility, Term Loan Facility, and the Unsecured Notes (see Note6 for additional details), and $175.2 million for postpetition interest, related to the Bankruptcy Court order denying our objection to postpetition interestclaims, at the default rate for the period beginning April 29, 2016 through April 12, 2017, as described in Note 12.Restructuring Expense. During the year ended December 31, 2016, the Company incurred $7.2 million in costs and fees in connection with its effortsto restructure its debt prior to filing the chapter 11 petitions.Contract Settlement. Contract settlement expense decreased to $52.7 million for the year ended December 31, 2017, compared to $131.1 million forthe year ended December 31, 2016. The decrease relates to the contract settlement of $57.0 million reached with Sempra Rockies Marketing, LLC during theyear ended December 31, 2017 as compared to the contract settlement of $150.0 million reached with REX during the year ended December 31, 2016.Deferred Gain on Sale of Liquids Gathering System. During the years ended December 31, 2017 and 2016, the Company recognized $10.6 million indeferred gain on sale of the liquids gathering system relating to the Pinedale LGS in December 2012.43Table of Contents Commodity Derivatives:Gain (Loss) on Commodity Derivatives. During the year ended December 31, 2017, the Company recognized a gain of $28.4 million related tocommodity derivatives. Of this total, the Company recognized $11.4 million of realized gain during the year ended December 31, 2017. The realized gain orloss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain on commodity derivatives alsoincludes a $17.0 million of unrealized gain on commodity derivatives at December 31, 2017. The unrealized gain or loss on commodity derivativesrepresents the change in the fair value of these derivative instruments over the remaining term of the contract. The Company did not have any opencommodity derivatives at December 31, 2016.Reorganization Items:Reorganization Items, Net. Reorganization items, net represented an income of $140.9 million for the year ended December 31, 2017 compared to anexpense of $47.5 million for the same period in 2016. The increase is due to the Company’s emergence from chapter 11 proceedings during the year endedDecember 31, 2017, and is primarily comprised of expenses of $66.4 million in professional fees, settlements, and interest income associated with theCompany’s chapter 11 cases and of $223.8 million related to the Bankruptcy Court order denying our objection to the make-whole claims offset by a gain of$431.1 million, which primarily represents the gain on the debt for equity exchange related to the Company’s prepetition senior notes.Income from Operations:Pretax Income. The Company recognized income before taxes of $163.8 million for the year ended December 31, 2017 compared with income of$55.5 million for the same period in 2016. The increase in earnings is primarily attributable to increased revenues due to increases in the average oil andnatural gas prices and the net effect of the reorganization items, partially offset by an increase in interest expense, DD&A, and general and administrativeexpense during the year ended December 31, 2017.Income Taxes. The Company recorded a $13.3 million tax benefit related to expected U.S. cash tax refunds for the year ended December 31,2017. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of December 31, 2017. Some or all ofthis valuation allowance may be reversed in future periods against future income.Net Income. For the year ended December 31, 2017, the Company recognized a net income of $177.1 million or $1.08 per diluted share as comparedwith a net income of $56.2 million or $0.70 per diluted share for the same period in 2016. The increase in earnings is primarily attributable to increasedrevenues due to increases in the average oil and natural gas prices and the net effect of the reorganization items, partially offset by an increase in interestexpense, DD&A, and general and administrative expense during the year ended December 31, 2017.LIQUIDITY AND CAPITAL RESOURCESOverview. During the year ended December 31, 2018, we funded our operations primarily through cash flows from operating activities and borrowingsunder the Revolving Credit Facility. In addition to cash flows from operations, the Revolving Credit Facility is our primary source of liquidity. AtDecember 31, 2018, the Company reported a cash position of $17.0 million. At December 31, 2018, the Company had $104.0 million of outstandingborrowings under the Revolving Credit Facility. In addition to the borrowings outstanding under the Revolving Credit Facility, the Company had $1.9billion of other indebtedness outstanding in the form of term loans, secured notes and unsecured notes with maturities commencing in 2022. The borrowingbase provides for a total of $325.0 million of availability. Availability may be limited based on compliance with financial covenants; however, subsequent tothe Fourth Amendment to the Credit Agreement dated February 14, 2019, the Company expects to have adequate liquidity to fund its operations into theforeseeable future.Given the current level of volatility in the market and unpredictability of certain costs that could potentially arise in our operations, the Company’sliquidity needs could be significantly higher than the Company currently anticipates. The Company’s ability to maintain adequate liquidity depends on theprevailing market prices for oil and natural gas, the successful operation of the business, and appropriate management of operating expenses and capitalspending. The Company’s anticipated liquidity needs are highly sensitive to changes in each of these and other factors. Capital Expenditures. For the year ended December 31, 2018, total capital expenditures were $426.2 million. During this period, the Companyparticipated in 135 gross (100.5 net) wells in Wyoming that were drilled to total depth and cased. No wells were drilled in Utah during 2018.2019 Capital Investment Plan. For 2019, our capital expenditures are expected to be approximately $320 million to $350 million, includingcapitalized general and administrative costs. We expect to fund these capital expenditures through cash flows from operations, borrowings under theRevolving Credit Facility, and cash on hand. We expect to allocate all of the budget to development activities in our Pinedale field.44Table of Contents Ultra Resources, Inc.Credit Agreement. On April 12, 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (the “Credit Agreement”) with the Companyand UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the otherlenders party thereto (collectively, the “RBL Lenders”) from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) subjectto borrowing base redetermination which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (asdefined below). In September 2018, the borrowing base was reduced from $1.4 million to $1.3 billion in connection with the semi-annual determination, with$975.0 million allocated to the Company’s Term Loan Facility (defined below), resulting in $325.0 million of borrowing base under the Revolving CreditFacility as of the end of 2018. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into theThird Amendment to the Credit Agreement (the “Third Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to theThird Amendment, the parties agreed, among other things, to amend the Credit Agreement to permit the issuance of the Second Lien Notes and the ExchangeTransaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to: •increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Credit Agreement); •removing the ability to create, invest in and utilize unrestricted subsidiaries; •further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as morethoroughly described in the Third Amendment; and •providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the ThirdAmendment.In conjunction with the Exchange Transaction, the Third Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications andExtinguishments specifically for modifications to or exchanges of revolving-debt arrangements. Based on the guidance, the unamortized deferred costs, anyfees paid to the creditor, and any third-party costs associated with Third Amendment, which were incurred as part of the Exchange Transaction, will bedeferred and amortized over the term of the Credit Agreement because the borrowing capacity did not change. Deferred financing costs, including the newcosts incurred as part of the Exchange Transaction, are recorded as Other assets on the Consolidated Balance Sheets in accordance with ASU No. 2015-15.On February 14, 2019, Ultra Resources entered into a Fourth Amendment to the Credit Agreement (the “Fourth Amendment”) with the RBLAdministrative Agent and the RBL Lenders party thereto. Pursuant to the Fourth Amendment, the borrowing base was reaffirmed at $1.3 billion with $325million of borrowing base available under the Revolving Credit Facility.The Fourth Amendment also revises certain covenants and other provisions of the Credit Agreement, including, but not limited to: •Amending the consolidated net leverage ratio financial covenant as described below. In addition, the consolidated net debt component of theconsolidated net leverage ratio may be reduced upon the receipt of proceeds from the make-whole litigation; •Revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that representan accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to seniormanagement changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debtrestructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of anaccrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certainnoncash charges that Ultra Resources chose to add back (as described in clause (i)); and •Amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, current requiredamortization payments under the Term Loan Agreement.At December 31, 2018, Ultra Resources had $104.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments underthe Revolving Credit Facility of $325.0 million, and a borrowing base of $1.3 billion. Given that the Revolving Credit Facility was amended in February2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is October 1, 2019.The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of thecommitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary Londoninterbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of anyfiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwiseapply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. TheRevolving Credit Facility loans mature on January 12, 2022.45Table of Contents Under the Fourth Amendment, Ultra Resources is required to maintain (i) a minimum interest coverage ratio of 2.50 to 1.00; (ii) a current ratio,including the unused portion of the Revolving Credit Facility, of a minimum of 1.00 to 1.00; and (iii) after the Company has obtained investment graderating an asset coverage ratio of 1.50 to 1.00. In addition, as of the last day of (i) the fiscal quarter ending December 31, 2018, Ultra Resources will not permitthe consolidated net leverage ratio to exceed 4.50 to 1.0, (ii) each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019, UltraResources will not permit the consolidated net leverage ratio to exceed 4.75 to 1.0, (iii) each fiscal quarter ending during the period from September 30, 2019through June 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.90 to 1.0, (iv) the fiscal quarter ending September 30,2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.5 to 1.0, and (v) the fiscal quarter ending December 31, 2020 and eachother fiscal quarter end thereafter, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.25 to 1.0.At December 31, 2018, Ultra Resources’ consolidated net leverage ratio, as defined in the Credit Agreement, was 3.95 to 1.00, and it was in compliancewith each of its debt covenants under the Revolving Credit Facility.Under the Revolving Credit Facility, the Company is subject to minimum hedging requirements. Through September 29, 2019, the Company isrequired to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its proved developed producing (“PDP”) reserves; and during theperiod beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projectedvolumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon aborrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees.The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws(including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports,maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions,fundamental changes, restricted payments, hedging requirements and other customary covenants.The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not complywith the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of allamounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated.Term Loan. On April 12, 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement (the “Term Loan Agreement”) withthe Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent (the “Term Loan Administrative Agent”), andthe other lenders party thereto (collectively, the “Term Loan Lenders”), providing for senior secured first lien term loans for an aggregate amount of $800.0million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawnimmediately after the funding of the initial term loan. In September 2017, the Company closed an incremental senior secured term loan offering of $175.0million, increasing total borrowings under the Term Loan Agreement to $975.0 million. As part of the Term Loan Agreement, Ultra Resources agreed to payan original issue discount equal to one percent of the principal amount, which is included in the deferred financing costs. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into theFirst Amendment to the Term Loan Agreement (the “Term Loan Amendment”) with the Term Loan Administrative Agent and the Term Loan Lenders partythereto. Pursuant to the Term Loan Amendment, the parties agreed, among other things, to amend the Term Loan Agreement to permit the issuance of theSecond Lien Notes and the Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payablein cash and 25 basis points payable in kind (“PIK”), and to revise certain covenants and other provisions of the Term Loan Agreement, including, but notlimited to: •introducing call protection of 102% until the first anniversary of the Exchange Transaction and 101% until the second anniversary of theExchange Transaction (defined below); •introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility asmore thoroughly described in the Term Loan Amendment; •deleting the ability to increase commitments under the Term Loan; •increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement); •removing the ability to create, invest in and utilize unrestricted subsidiaries; •further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as morethoroughly described in the Term Loan Amendment; and •providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term LoanAmendment.At December 31, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Facility.46Table of Contents Following the Exchange Transaction, the Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable in- kind upon election byUltra Resources. The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principalamount beginning on June 30, 2019. The Term Loan Facility matures on April 12, 2024.In conjunction with the Exchange Transaction, the Term Loan Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications andExtinguishments. The instrument was determined to not be substantially different and debt modification accounting was applied as this transaction was not atroubled debt restructuring (“TDR”), as defined in the accounting literature. As a result, no gain or loss was recorded. New fees paid to the Term Loan Lenderstotaled $7.2 million and are included as deferred financing costs which is direct deduction from the carrying amount of the Term Loan.The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, withoutlimitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss ofUltra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement ifthe asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term LoanFacility.The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (includingenvironmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenanceand operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes,restricted payments and other customary covenants. At December 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the TermLoan Agreement.The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not complywith the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of allamounts outstanding under the Term Loan Agreement.Second Lien Notes. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources issued $545.0 millionaggregate principal amount of Second Lien Notes and entered into an Indenture, dated as of December 21, 2018 (the “Second Lien Notes Indenture”), amongUltra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”) andcollateral agent.The Second Lien Notes will mature on July 12, 2024. Interest on the Second Lien Notes will accrue at (i) an annual rate of 9.00% payable in cash and(ii) an annual rate of 2.00% PIK. The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15,2019.The Second Lien Notes are senior secured obligations of Ultra Resources and rank senior in right of payment to all of its existing and future unsecuredsenior debt, to the extent of the value of the collateral pledged under the Second Lien Notes Indenture and related collateral arrangements, senior in right ofpayment to all of its future subordinated debt, and junior in right of payment to all of its existing and future secured debt of senior priority, to the extent ofthe value of the collateral pledged thereby. The Second Lien Notes are secured by second priority security interests in substantially all assets of theCompany. Payment by Ultra Resources of all amounts due on or in respect of the Second Lien Notes and the performance of Ultra Resources under theSecond Lien Notes Indenture are initially guaranteed by the Company.Prior to December 21, 2021, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principalamount of the Second Lien Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 111.000% of theprincipal amount of the Second Lien Notes, plus accrued and unpaid interest (including PIK interest), if any, to the date of redemption, if at least 65% of theoriginal principal amount of the Second Lien Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. Inaddition, before December 21, 2019, Ultra Resources may redeem all or a part of the Second Lien Notes at a redemption price equal to the sum of (i) theprincipal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest (including PIK interest), if any, to theredemption date. In addition, on or after December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at redemption prices(expressed as percentages of principal amount) equal to 105.500% for the twelve-month period beginning on December 21, 2021, 102.750% for the twelve-month period beginning December 21, 2022, and 100.000% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plusaccrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes.If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second LienNotes may require the Issuer to repurchase all or a portion of its Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount ofsuch Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase.47Table of Contents The Second Lien Notes Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of itssubsidiaries to: (i) sell assets and subsidiary equity; (ii) incur or redeem indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v)pay cash dividends, (vi) change the nature of its business or operations, (vii) make certain types of investments, (ix) enter into agreements that restrictdistributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (x) consolidate, merge or transfer all or substantiallyall of the assets of the Company or any Restricted Subsidiary (as defined in the Second Lien Notes Indenture); and (xi) create unrestricted and foreignsubsidiaries. The covenants in the Second Lien Notes Indenture are subject to important exceptions and qualifications. Subject to conditions, the SecondLien Notes Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Second Lien Notes receiveinvestment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc.The Second Lien Notes Indenture contains customary events of default. Unless otherwise noted in the Second Lien Notes Indenture, upon a continuingevent of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Second Lien Notes, bynotice to the Company and the Trustee, may declare the Second Lien Notes immediately due and payable, except that an event of default resulting from entryinto a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) orgroup of Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, willautomatically cause the Second Lien Notes to become due and payable.In conjunction with the Exchange Transaction, the portion of the senior Unsecured Notes which were exchanged for Second Lien Notes was accountedfor as a TDR. The Company evaluated the quantitative and qualitative factors in the accounting literature and concluded that concessions were granted as thefuture undiscounted cash flows of the Second Lien Notes was greater than the net carrying value of the senior Unsecured Notes. No gain is recognized, and aneffective interest rate is established based on the carrying value of the original Second Lien Notes and revised cash flows. The amount of extinguished debtwill be amortized over the remaining life of the Second Lien Notes using the effective interest method and recognized as a reduction to interest expense. As aresult, our reported interest expense following the Exchange Transaction will be significantly less than the contractual cash interest payments throughout theterm of the Second Lien Notes.The Exchange Transaction for the Second Lien Notes resulted in recognition of $4.7 million in expenses for the year ended December 31, 2018.The exchanged debt resulted in a calculation of cancellation of debt income for tax purposes. Our current tax attributes are expected to offset anypotential cash tax impacts from the Exchange Transaction.Senior Unsecured Notes. On April 12, 2017, Ultra Resources issued $700.0 million of its 2022 Notes $500.0 million of its 2025 Notes and entered intoan Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, asguarantors, and Wilmington Trust, National Association, as Trustee. The Unsecured Notes are treated as a single class of securities under the Unsecured NotesIndenture.On December 21, 2018, the Company completed the Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) $505million aggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principal amount, or 55.0%, of theissued and outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes and (b) an aggregate of 10,919,499 new warrantsof the Company each entitling the holder thereof to purchase one common share of the Company. As a result of the Exchange Transaction, at December 31,2018, the aggregate principal amounts outstanding under the Unsecured Notes were approximately $195.0 million with respect to the 2022 Notes and $225.0million with respect to the 2025 Notes.The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Noteswill mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the UnsecuredNotes from the issue date until maturity. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources, the Company and its other subsidiaries, asguarantors, and the Trustee entered into the First Supplement Indenture to the Unsecured Indenture (the “Supplemental Indenture”). Pursuant to theSupplemental Indenture, the parties amended the Unsecured Indenture to, among other things, eliminate or amend substantially all of the restrictivecovenants contained in the Unsecured Indenture, other than those relating to the payment of principal and interest. The Supplemental Indenture is binding onall Unsecured Notes that remain outstanding.The Unsecured Notes Indenture contains customary events of default. Unless otherwise noted in the Unsecured Notes Indenture, upon a continuingevent of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, bynotice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entryinto a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Unsecured Notes Indenture) orgroup of Restricted Subsidiaries (as defined in the Unsecured Notes Indenture), that taken together would constitute a Significant Subsidiary, willautomatically cause the Unsecured Notes to become due and payable.48Table of Contents Cash flows provided by (used in): Operating Activities. During the year ended December 31, 2018, net cash provided by operating activities was $310.9 million, a 376% increase fromnet cash provided by operating activities of $65.3 million for the same period in 2017. The increase in net cash provided by operating activities was largelyattributable to the payment of postpetition interest claims during the year ended December 31, 2017, as well as changes to working capital. There were nopostpetition interest payments during the year ended December 31, 2018.Investing Activities. During the year ended December 31, 2018, net cash used in investing activities was $401.7 million as compared to$435.3 million for the same period in 2017. The decrease in net cash used in investing activities is largely related to decreased capital investments associatedwith the Company’s drilling activities, partially offset by proceeds from the sale of certain non-core properties in Pennsylvania and Utah during 2017 and2018, respectively.Financing Activities. During the year ended December 31, 2018, net cash provided by financing activities was $91.8 million as compared to net cashused in financing activities of $16.7 million for the same period in 2017. The change in net cash used in financing activities is primarily due to theborrowings on the Credit Agreement as of December 31, 2018.OutlookWhile our net cash provided by operating activities will continue to be impacted by changing commodity prices, we believe that we will generatepositive cash flow from operations, which, along with our available cash and available borrowing capacity, will provide sufficient liquidity to fund ourcapital investments and operations over the next twelve months. We will continue to monitor and evaluate the impact of commodity prices in order todetermine the appropriate size and nature of our capital investment program.We expect to rely on our available cash, existing credit facility, and the cash generated from operations to meet our obligations. While we continue tomonitor the overall health of the credit markets, a renewed, long-term disruption in the credit markets could make financing more expensive or unavailable,which could have a material adverse effect on our operations.Off-Balance Sheet ArrangementsThe Company did not have any off-balance sheet arrangements as of December 31, 2018.Contractual ObligationsThe following table summarizes our contractual obligations as of December 31, 2018: Payments due by period: Total Less than1 year 1 to 3 years 3 to 5 years More than5 years (Amounts in thousands of U.S. dollars) Long-term debt $2,044,035 $7,313 $19,500 $318,535 $1,698,687 Interest payments (1) 797,361 146,860 280,394 259,784 110,323 Transportation contract (REX) 189,968 2,277 53,626 53,626 80,439 Operating lease — Liquids Gathering System 195,729 21,748 43,495 43,495 86,991 Office space lease 3,903 1,251 2,070 582 — Total contractual obligations $3,230,996 $179,449 $399,085 $676,022 $1,976,440(1)Interest payments include projected interest payments based on the variable interest rates which were calculated assuming a 3-month London interbankoffered rate plus the applicable basis points as of December 31, 2018. Outstanding debt and interest payments: The Company has debt financing agreements consisting of the Term Loan Facility, the Second Lien Notes,the Unsecured Notes, and the Revolving Credit Facility. See Note 6 for additional details. The Company included the principal and interest obligationsabove based on the respective agreements.Transportation contract. During our chapter 11 proceedings, REX filed a claim against us for $303.3 million for breach of contract. As previouslydisclosed, on January 12, 2017, we agreed to settle their claim and paid the settlement amounts of $150.0 million during the year ended December 31,2017. In connection with the settlement of REX’s proof of claim, the Company agreed to enter into a new transportation agreement pursuant to which theCompany will have firm transportation capacity of 200,000 Dekatherms per day at a rate of approximately $0.37 per Dekatherm on the Rockies ExpressPipeline, commencing on December 1, 2019 and extending for a term expiring December 31, 2026. This new agreement will provide the Company with theopportunity to transport a portion of its natural gas production away from its properties in Wyoming to capture improved basis differentials available at salespoints along the Rockies Express Pipeline, if any.49Table of Contents Operating lease. In 2012, the Company sold the Pinedale LGS and certain associated real property rights in the Pinedale Anticline in Wyoming. TheCompany entered into a long-term, triple net lease agreement relating to the use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initialterm of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the Pinedale LGS at the sole discretion of theCompany. Annual rent for the initial term under the Pinedale Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumerprice index) and may increase when certain volume thresholds are exceeded. The lease is classified as an operating lease under ASC 840 Leases.All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that couldresult in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classificationanalysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.Office space lease. The Company maintains office space in Colorado and Wyoming with total remaining commitments for office leases of$3.9 million at December 31, 2018.Critical Accounting PoliciesThe discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, whichhave been prepared in accordance with U.S. GAAP. In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect thereported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changesin these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amountsestimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve themost complex or subjective decisions or assessments.Oil and Gas Reserves. The reserve estimates presented herein were made in accordance with oil and gas reserve estimation and disclosureauthoritative accounting guidance according to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932,Extractive Activities — Oil and Gas (“FASB ASC 932”) as updated in order to align the reserve calculation and disclosure requirements with those in SECRelease No. 33-8995.The Company utilizes reliable technology such as seismic data and interpretation, wireline formation tests, geophysical logs and core data to assess itsresources. However, none of these technologies have contributed to a material addition to the proved reserves in this report.Estimates of proved crude oil and natural gas reserves require significant professional judgment and materially affect the Company’s depreciation,depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s DD&A rate will increase, resulting in adecrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additionaloperating history, mechanical problems on our wells and catastrophic events. Lower prices also make it uneconomical to drill wells or produce from fieldswith high operating costs.The Company’s proved reserves are a function of many assumptions, all of which could deviate materially from actual results. As a result, the estimatesof proved reserves could vary over time, and could vary from actual results.Full Cost Method of Accounting. The Company uses the full cost method of accounting for exploration and development activities as defined bythe SEC Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting StandardsBoard (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Additives — Oil and Gas (“FASB ASC 932”). Under this method ofaccounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includesany internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporateoverhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded on the fair valueof the asset retirement obligation when incurred. Gain or loss or other disposition of oil and natural gas properties is not recognized, unless the gain or losswould significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-productionmethod based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energycontent. Asset retirement costs are included in the base costs for calculating depletion.Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may beexcluded from capitalized costs being amortized. While the Company does not have any material amounts as described in this paragraph at the current time,it has been a larger consideration in prior years. The Company excludes significant costs until proved reserves are found or until it is determined that thecosts are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate thatthe recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discountednet cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well asappropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the relatedcommodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reducedby additional risk weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized.50Table of Contents Impairment of Oil and Gas Properties. Companies that use the full cost method of accounting for oil and natural gas exploration and developmentactivities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-XRule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for thepreceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value offuture net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties,less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cashcharge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization(“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increasethe ceiling.The Company did not have any write-downs related to the full cost ceiling limitation in 2018, 2017 or 2016. Deferred Financing Costs. The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying thePresentation of Debt Issuance Costs for its Term Loan Facility, Second Lien Notes, and the Unsecured Notes and includes the costs for issuing debt includingissuance discounts as a direct deduction from the carrying amount of the related debt liability. Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurementof Debt Issuance Costs Associated with Line of Credit Arrangements for its Revolving Credit Facility and includes the costs related to the issuance of theRevolving Credit Facility in Other assets on the Consolidated Balance Sheets.Asset Retirement Obligation. The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal,site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and EnvironmentalObligations (“FASB ASC 410”) requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with theassociated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that managementmake numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities,amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent toinitial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions toeither the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net incomeas accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.Revenue Recognition. The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market pricesand under multi-year contracts that provide for a fixed price of oil and natural gas. On January 1, 2018, the Company adopted the new accounting standard,ASC 606 Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosures related to the Company’sadoption of this standard.Valuation of Deferred Tax Assets. The Company uses the asset and liability method of accounting for income taxes. Under this method, futureincome tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis(temporary differences).To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred taxassets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods inwhich those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxableincome and tax planning strategies in making this assessment.The Company has recorded a valuation allowance against all of its deferred tax assets as of December 31, 2018. Some or all of this valuation allowancemay be reversed in future periods against future income.Derivative Instruments and Hedging Activities. The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). TheCompany records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fairvalue of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives.Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASBASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between marketparticipants at measurement date and establishes a three-level hierarchy for measuring fair value. The valuation assumptions the Company has used tomeasure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are consideredLevel 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). See Note 9 for additional information.51Table of Contents In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default byfailing to make contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Companyconsiders that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligationsassociated with the derivative transactions.Legal, Environmental and Other Contingencies. A provision for legal, environmental and other contingencies is charged to expense when the loss isprobable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts foraccrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based oninterpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitorsknown and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items basedon information available to the Company. Contingent gains arise if the outcome of future events may result in a possible gain or benefit to the Company andare recorded when the gain is realized.Share-Based Payment Arrangements. The Company follows FASB ASC Topic 718, Compensation — Stock Compensation (“FASB ASC 718”)which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, includingemployee stock options, based on estimated fair values. Share-based compensation expense recognized under FASB ASC 718 for the years endedDecember 31, 2018, 2017 and 2016 was $11.8 million, $40.0 million and $5.6 million, respectively. See Note 7 for additional information.Conversion of Barrels of Oil to Mcfe of Gas. The Company converts barrels of oil and other liquid hydrocarbons to Mcfe at a ratio of one barrel ofoil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrelof oil or other liquids to an Mcf of natural gas. The sales price of one barrel of oil or liquids has been much higher than the sales price of six Mcf of naturalgas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a barrel of oil or otherliquids.Recent accounting pronouncements.Revenues from Contracts with Customers: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting RevenueGross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, whichsupersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, ExtractiveActivities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services tocustomers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the“new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1,2018 due to the cumulative impact of adopting the new revenue standard, with the impact related to changing from the entitlements method to the salesmethod to account for wellhead imbalances. The impact to revenues for the twelve months ended December 31, 2018 is immaterial to the overallconsolidated financial statements as a result of applying the new revenue standard. The comparative information has not been restated and continues to bereported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. We expect the impact ofthe adoption of the new revenue standard to be immaterial to our net income on an on-going basis.Stock Compensation: In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which isintended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation,to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation ofthis ASU did not have a material impact on the Company’s consolidated financial statements.Leases: In February 2016, the FASB established Topic 842, Leases, by issuing issued ASU 2016-02, Leases (“ASU No. 2016-02”), which requireslessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability onthe balance sheet for all leases. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expenserecognition in the income statement.52Table of Contents On January 1, 2019, we adopted the new standard. A modified retrospective transition approach is required, applying the new standard to all leasesexisting at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative periodpresented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leasesalso apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financialstatements and provide the disclosures required by the new standard for the comparative periods. We adopted the new standard on January 1, 2019 and willuse the effective date as our date of initial application. Consequently, financial information will not be updated and the disclosures required under the newstandard will not be provided for dates and periods before January 1, 2019.The new standard provides a number of optional practical expedients in transition. We expect to elect the package of practical expedients, whichpermits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We also expectto adopt the practical expedient pertaining to land easements. We do not expect to elect the use-of-hindsight.The new standard also provides practical expedients for an entity’s ongoing accounting. We expect to elect the short-term lease recognition exemptionfor all leases that qualify. For those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets orlease liabilities for existing short-term leases of those assets in transition. We will continue to evaluate the practical expedients related to lease and non-leasecomponents.We expect that this standard will have a material effect on our financial statements. While we continue to assess all of the effects of adoption, wecurrently believe the most significant effects relate to (1) the recognition of new ROU assets and lease liabilities on our balance sheet for our office andequipment operating leases; and (2) the requirement to provide significant new disclosures about our leasing activities. These ROU assets and liabilities arenot deemed to be debt within the definitions of our debt covenants.On adoption, we currently expect to recognize additional operating liabilities with corresponding ROU assets of the same amount based on the presentvalue of the remaining minimum rental payments under current leasing standards for existing operating leases.Derivatives: In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815) (“ASU No. 2017-12”), which makes significantchanges to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships, measurement of hedging relationships,presentation of the effects of hedging relationships, assessment of hedge effectiveness, and disclosures. The guidance is effective for annual periodsbeginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12to have a material impact on its consolidated financial statements as the Company does not elect hedge accounting. Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework —Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair valuemeasurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein.Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements.53Table of Contents Item 7A.Quantitative and Qualitative Disclosures About Market RiskObjectives and Strategy: The Company is exposed to commodity price risk. The following quantitative and qualitative information is providedabout financial instruments to which we were a party at December 31, 2018, and from which we may incur future gains or losses from changes in commodityprices. We do not enter into derivative or other financial instruments for speculative or trading purposes.The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently drivenprimarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile andunpredictable. Pricing volatility is expected to continue. The prices we receive for our production depend on many factors outside of our control, includingvolatility in the differences between product prices at sales points and the applicable index price.The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty inthe Company’s forward cash flows supporting the Company’s capital investment program. These types of instruments may include fixed price swaps, costlesscollars, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedgedcommodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increasesin commodity prices above the fixed hedge prices.Under the Revolving Credit Facility, the Company is subject to minimum hedging requirements. Through September 29, 2019, the Company isrequired to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its proved developed producing (“PDP”) reserves; and during theperiod beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projectedvolumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecasted production volumes without Boardapproval. During 2018, the Board approved all commodity derivative hedge contracts for volumes exceeding 50% of forecasted production volumes.Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liabilityand be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.The Company does not apply hedge accounting to any of its derivative instruments.Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balancesheet and the associated unrealized gains and losses are recorded as current expense or income in the income statement. Unrealized gains or losses oncommodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cashflow statement.Commodity Derivative Contracts: At December 31, 2018, the Company had the following open commodity derivative contracts to managecommodity price risk. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty. Forthe basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified timeperiod. For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays the Company if the marketprice is below the floor price on a notional quantity. The reference prices of these commodity derivative contracts are typically referenced to index prices aspublished by independent third parties. Type Index Total Volumes(in millions) Weighted Average Price Per Unit Fair Value -December 31, 2018 Asset(Liability) Natural Gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 NYMEX-Henry Hub 185.9 $2.81 $(12,832)2020 NYMEX-Henry Hub 22.8 $2.76 $(4,506) Natural Gas basis swaps (Mmbtu) ($/Mmbtu) 2019 NW Rockies Basis Swap 105.9 $0.67 $(41,286) Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 NYMEX-WTI 1.4 $58.45 $15,143 2020 NYMEX-WTI 0.1 $60.05 $994 Type Index Total Volumes(in millions) WeightedAverageFloor Price WeightedAverageCeiling Price Fair Value -December 31, 2018 Asset(Liability) Natural Gas collars ($/MMBTU) 2020 NYMEX 9.1 $2.75 $3.19 $(346) 54Table of Contents Subsequent to December 31, 2018 and through February 28, 2019, the Company has closed out several oil contracts prior to their scheduled settlementdates and entered into the following commodity derivative contracts to manage commodity price risk. Type Remaining Contract Period Index Volume/MMBTU/Day Average Price/MMBTU Natural gas fixed price swaps Apr. 2019 - Oct. 2019 NYMEX-Henry Hub 40,000 $2.90 Type Remaining Contract Period Index Volume/MMBTU/Day Average Differential/MMBTU Natural gas basis swaps Apr. 2019 - Oct. 2019 NYMEX-Henry Hub 100,000 $(0.52) Jul. 2019 - Sept. 2019 NYMEX-Henry Hub 50,000 $(0.34) Type Remaining Contract Period Index Volume/Bbls/Day Average Price/Bbls Crude oil fixed price swaps Apr. 2019 - Dec. 2019 NYMEX-WTI 1,000 $56.75 Apr. 2019 - Jun. 2019 NYMEX-WTI 1,000 $57.70 Type Remaining Contract Period Index Volume/MMBTU/Day Weighted AverageFloor Price//MMBTU Weighted AverageCeilingPrice/MMBTU Natural gas collars Jan. 2020 - Mar. 2020 NYMEX 10,000 $2.80 $3.30 Apr. 2020 - Jun. 2020 NYMEX 236,000 $2.32 $2.83 Type Remaining Contract Period Index Volume/MMBTU/Day Weighted AverageFloor Price/MMBTU Premium Natural gas put options Apr. 2020 - Jun. 2020 NYMEX 114,000 $2.41 $(1,287,650)(1)Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the lasttrading day of the month by the NYMEX for natural gas swaps for the respective period.The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivativeinstruments in the Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016: For the Year Ended December 31, Commodity Derivatives (000’s): 2018 2017 2016 Realized gain (loss) on commodity derivatives-natural gas (1) $(77,031) $11,446 $— Realized gain (loss) on commodity derivatives-crude oil(1) (8,382) — — Unrealized gain (loss) on commodity derivatives (1) (59,799) 16,966 — Total gain (loss) on commodity derivatives $(145,212) $28,412 $— (1)Included in gain (loss) on commodity derivatives in the Consolidated Statements of Operations. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivativecontracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remainingterm of the contract. 55Table of Contents Item 8.Financial Statements and Supplementary Data.MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of the Company is responsible for the preparation and integrity of all information contained in this Annual Report. Theaccompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. Thefinancial statements include amounts that are management’s best estimates and judgments.Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in ExchangeAct Rules 13a-15(f). Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, weconducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our evaluation under theframework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as ofDecember 31, 2018.Ernst & Young LLP, the independent registered public accounting firm that audited the accompanying financial statements included in this AnnualReport, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their reportwhich is included herein.56Table of Contents Report of Independent Registered Public Accounting Firm The Shareholders and Board of Directors of Ultra Petroleum Corp. and subsidiariesOpinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries (the Company) as of December 31, 2018 and 2017,the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018, andthe related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, inall material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of thethree years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company'sinternal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 7, 2019 expressed an unqualifiedopinion thereon. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financialstatements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Companyin accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing proceduresto assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also includedevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financialstatements. We believe that our audits provide a reasonable basis for our opinion. /s/ Ernst & Young LLPWe have served as the Company’s auditor since 2006. Denver, ColoradoMarch 7, 201957Table of Contents Report of Independent Registered Public Accounting Firm To the Shareholders and the Board of Directors of Ultra Petroleum Corp. and subsidiariesOpinion on Internal Control over Financial ReportingWe have audited Ultra Petroleum Corp. and subsidiaries’ internal control over financial reporting as of December 31, 2018, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSOcriteria). In our opinion, Ultra Petroleum Corp. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financialreporting as of December 31, 2018, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidatedbalance sheets of the Company as of December 31, 2018 and 2017, the related statements of operations, shareholders’ equity, and cash flows for each of thethree years in the period ended December 31, 2018, and the related notes and our report dated March 7, 2019 expressed an unqualified opinion thereon.Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Ourresponsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing andevaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considerednecessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate. /s/ Ernst & Young LLPDenver, ColoradoMarch 7, 2019 58Table of Contents ULTRA PETROLEUM CORP. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS December 31, 2018 2017 (Amounts in thousands ofU. S. dollars, except share data) ASSETS Current assets: Cash and cash equivalents $17,014 $16,631 Restricted cash 2,291 1,638 Oil and gas revenue receivable 133,042 86,487 Joint interest billing and other receivables, net 11,348 16,616 Derivative asset 23,374 16,865 Income tax receivable 6,431 10,091 Inventory 18,757 13,450 Other current assets 2,473 5,647 Total current assets 214,730 167,425 Oil and gas properties, net, using the full cost method of accounting: Proven 1,497,727 1,325,068 Property, plant and equipment 11,635 9,569 Other 9,196 10,920 Total assets $1,733,288 $1,512,982 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable $36,923 $59,951 Accrued liabilities 58,574 80,268 Production taxes payable 58,365 51,352 Current portion of long-term debt 7,313 — Interest payable 28,672 24,406 Capital cost accrual 15,014 32,513 Derivative liability 62,350 — Total current liabilities 267,211 248,490 Long-term debt Long-term debt 2,036,722 2,175,000 Add: Premium on exchange transaction 228,096 — Less: Unamortized deferred financing costs and discount (56,650) (58,789)Total long-term debt, net 2,208,168 2,116,211 Deferred gain on sale of liquids gathering system 94,636 105,189 Other long-term obligations 211,895 197,728 Total liabilities 2,781,910 2,667,618 Commitments and contingencies (Note 12) Shareholders’ equity: Common stock — no par value; authorized — 750,000,000; issued and outstanding shares — 197,383,295 and 196,346,736 at December 31, 2018 and 2017, respectively 2,137,443 2,116,018 Treasury stock (49) (49)Retained loss (3,186,016) (3,270,605)Total shareholders’ deficit (1,048,622) (1,154,636)Total liabilities and shareholders’ equity $1,733,288 $1,512,982 Approved on behalf of the Board: /s/ Brad Johnson /s/ Michael J. KeeffePresident, Chief Executive Officer and Director Director See accompanying notes to consolidated financial statements. 59Table of Contents ULTRA PETROLEUM CORP. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2018 2017 2016 (Amounts in thousands of U.S. dollars,except per share data) Revenues: Natural gas sales $722,313 $748,682 $609,756 Oil sales 153,534 133,368 111,335 Other revenues 16,652 9,823 — Total operating revenues 892,499 891,873 721,091 Expenses: Lease operating expenses 90,290 92,326 89,134 Facility lease expense 25,947 21,749 20,686 Production taxes 93,322 91,067 69,737 Gathering fees 89,806 86,953 86,809 Transportation charges — — 20,049 Depletion, depreciation and amortization 204,255 161,945 125,121 General and administrative 25,005 39,548 9,179 Other expenses 9,118 — — Total operating expenses 537,743 493,588 420,715 Operating income 354,756 398,285 300,376 Other (expense) income, net: Interestexpense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016) (148,316) (361,367) (66,565)Gain (loss) on commodity derivatives (145,212) 28,412 — Deferred gain on sale of liquids gathering system 10,553 10,553 10,553 Restructuring expenses — — (7,176)Contract settlement income (expense), net 12,656 (52,707) (131,106)Other income (expense), net 1,212 (237) (3,082)Total other (expense) income, net (269,107) (375,346) (197,376)Reorganization items, net — 140,907 (47,503)Income before income tax expense (benefit) 85,649 163,846 55,497 Income tax expense (benefit) 442 (13,294) (654)Net income $85,207 $177,140 $56,151 Basic Earnings per Share: Net income per common share — basic $0.43 $1.08 $0.70 Fully Diluted Earnings per Share: Net income per common share — fully diluted $0.43 $1.08 $0.70 Weighted average common shares outstanding — basic 196,964 163,824 79,996 Weighted average common shares outstanding — fully diluted 197,541 163,976 80,363 See accompanying notes to consolidated financial statements. 60Table of Contents ULTRA PETROLEUM CORP. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY(Amounts in thousands of U.S. dollars, except share data) SharesIssued andOutstanding CommonStock RetainedLoss TreasuryStock TotalShareholders’(Deficit)Equity Balances at December 31, 2015 79,933 $502,050 $(3,493,811) $(176) $(2,991,937)Employee stock plan grants 145 — — — — Shares re-issued from treasury — — (127) 127 — Net share settlements (61) — (378) — (378)Fair value of employee stock plan grants — 8,013 — — 8,013 Net income — — 56,151 — 56,151 Balances at December 31, 2016 80,017 $510,063 $(3,438,165) $(49) $(2,928,151)Equitization of Holdco Notes 70,579 978,230 — — 978,230 Rights Offering, including Backstop 44,390 573,774 — — 573,774 Employee stock plan grants 10 — — — — Stock plan grants 2,191 26,673 — — 26,673 Net share settlements (840) — (9,580) — (9,580)Fair value of employee stock plan grants — 27,278 — — 27,278 Net income — — 177,140 — 177,140 Balances at December 31, 2017 196,347 $2,116,018 $(3,270,605) $(49) $(1,154,636)Employee stock plan grants 1,770 — — — — Net share settlements (734) — (2,379) — (2,379)Issuance of warrants — 5,786 — — 5,786 Fair value of employee stock plan grants — 15,639 — — 15,639 Initial adoption of ASC 606 — — 1,761 — 1,761 Net income — — 85,207 — 85,207 Balances at December 31, 2018 197,383 $2,137,443 $(3,186,016) $(49) $(1,048,622) See accompanying notes to consolidated financial statements. Shareholders’ Equity Explanatory Note:In conjunction with emergence from chapter 11 proceedings in April 2017, the Company issued new common shares of the Company (the “NewEquity”) to holders of existing pre-petition common shares of the Company (the “Existing Common Shares”) at a conversion ratio of 0.521562. As a result,the share counts have been adjusted to reflect this conversion as if it had occurred as of the earliest period presented.Consistent with the Plan, 194,991,656 shares of New Equity were issued as follows: •70,579,367 shares of New Equity were issued pro rata to holders of the Company’s prepetition senior notes with claims allowed under theDebtors’ Second Amended Joint Chapter 11 Plan of Reorganization; •80,022,410 shares of New Equity were issued pro rata to holders of Existing Common Shares; •2,512,623 shares of New Equity were issued to commitment parties under the backstop commitment agreement in respect of the commitmentpremium due thereunder; •18,844,363 shares of New Equity were issued to commitment parties under the backstop commitment agreement in connection with theirbackstop obligation thereunder; and •23,032,893 shares of New Equity were issued to participants in the rights offering completed pursuant to the Plan. 61Table of Contents ULTRA PETROLEUM CORP. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 2017 2016 (Amounts in thousands of U.S. dollars) Cash provided by (used in): Operating activities: Net income for the period $85,207 $177,140 $56,151 Adjustments to reconcile net income to cash provided by operating activities: Depletion, depreciation and amortization 204,255 161,945 125,121 Unrealized (gain) loss on commodity derivatives 59,799 (16,966) — Deferred gain on sale of liquids gathering system (10,553) (10,553) (10,553)Stock compensation 11,825 39,977 5,562 Non-cash reorganization items, net — (453,909) 42,523 Amortization of premium on restructuring (1,083) — — Amortization of deferred financing costs 11,210 7,483 4,194 Other 3,501 (1,047) 2,676 Net changes in operating assets and liabilities: Accounts receivable (46,276) (14,483) (19,635)Other current and non-current assets 5,630 14,615 (16,186)Accounts payable (13,206) 34,349 (63,924)Accrued liabilities (20,294) 89,935 133,144 Production taxes payable 7,098 7,023 (7,944)Interest payable 4,266 36,220 57,117 Other long-term obligations 2,674 4,737 276 Current taxes payable/receivable 6,844 (11,198) 2,548 Net cash provided by operating activities 310,897 65,268 311,070 Investing Activities: Oil and gas property expenditures (426,166) (557,029) (269,314)Sale of oil and gas properties 61,304 114,263 — Change in capital cost accrual and accounts payable (27,322) 20,076 (8,134)Inventory (5,335) (8,916) (1,123)Proceeds from sale of property, plant and equipment 2,872 — — Purchase of property, plant and equipment (7,063) (3,705) (329)Net cash used in investing activities (401,710) (435,311) (278,900)Financing activities: Borrowings under Credit Agreement 1,020,000 773,000 369,000 Payments under Credit Agreement (916,000) (773,000) — Borrowings under Term Loan — 975,000 — Extinguishment of long-term debt (chapter 11) — (2,459,000) — Proceeds from issuance of Senior Notes — 1,200,000 — Deferred financing costs (9,773) (73,092) — Shares issued, net of transaction costs — 573,774 — Repurchased shares/net share settlements (2,378) (9,581) (379)Debt extinguishment costs — (223,838) — Net cash provided by (used in) financing activities 91,849 (16,737) 368,621 (Decrease)/Increase in cash during the period 1,036 (386,780) 400,791 Cash, cash equivalents, and restricted cash at beginning of period 18,269 405,049 4,258 Cash, cash equivalents, and restricted cash end of period $19,305 $18,269 $405,049 Supplemental cash flow disclosures Cash paid for: Interest $135,230 $317,120 $4,793 Income taxes $— $— $94 Supplemental non-cash investing and financing activities Premium on Exchange Transaction $229,179 $— $— Principal reduction from exchange transaction $(229,179) $— $— See accompanying notes to consolidated financial statements. 62Table of ContentsULTRA PETROLEUM CORP. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS(All amounts in this Report on Form 10-K are expressed in thousands of U.S. dollars (except per share data), unless otherwise noted).DESCRIPTION OF THE BUSINESS:Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, or “us”)is an independent oil and gascompany engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporatedunder the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonahfields of the Green River Basin of Wyoming. 2018 Debt ExchangeIn December 2018, the Company exchanged (i) $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022Notes”) and (ii) $275 million aggregate principal amount, or 55.0%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of the Company, for (a)$545.0 million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “SecondLien Notes”), and (b) an aggregate of 10,919,499 new $0.01 warrants of the Company entitling the holder thereof to purchase one common share of theCompany (each a “Warrant” and collectively, the “Warrants”) (such transaction, the “Exchange Transaction”). The Exchange Transaction reducedindebtedness by approximately $235 million. Refer to Note 6 for additional details and the accounting treatment on the Exchange Transaction.1.SIGNIFICANT ACCOUNTING POLICIES:Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its whollyowned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated.Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cashequivalents.Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of theproduction is unknown or in dispute.The Company adopted Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash and reports the changein cash, cash equivalents, and restricted cash in total on the Consolidated Statement of Cash Flows as of December 31, 2017. The Consolidated Statement ofCash Flows as of December 31, 2016 has been adjusted to conform to the new standard. See the following table for a reconciliation of cash, cash equivalents,and restricted cash reported within the Consolidated Financial Statements:Current Presentation December 31, 2018 December 31, 2017 December 31, 2016 Cash and Cash Equivalents $17,014 $16,631 $401,478 Restricted Cash 2,291 1,638 3,571 Total cash, cash equivalents, and restricted cash $19,305 $18,269 $405,049 Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts.Included in the Other expenses on the Consolidated Statements of Operations is the provision for uncollectible accounts of $4.9 million. The carryingamount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assessesthe collectability of all material trade and other receivables.Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respectiveuseful life.63Table of Contents Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by theSecurities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”)and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASBASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oiland gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs relatedto production, general corporate overhead or similar activities. Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded fromamortization and actively being evaluated, if any. The carrying amount of oil and natural gas properties also includes estimated asset retirement costsrecorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas propertiesis not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gasattributable to a country.The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-productionmethod based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energycontent. Asset retirement costs are included in the base costs for calculating depletion.Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may beexcluded from capitalized costs being amortized. While the Company does not have any material amounts as described in this paragraph at the current time,it has been a larger consideration in prior years. The Company excludes significant costs until proved reserves are found or until it is determined that thecosts are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate thatthe recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discountednet cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well asappropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the relatedcommodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reducedby additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized.Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceilingtest calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performedquarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period inaccordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable toproved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. Ifsuch capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any suchwrite-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods.A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.The Company did not have any write-downs related to the full cost ceiling limitation in 2018, 2017 or 2016. Inventories: Inventory includes $17.6 million in pipe and production equipment and miscellaneous materials and supplies that will be utilizedduring the 2019 drilling program, as well as $1.1 million in crude oil inventory. Our inventories are valued at the lower of cost or net realizable value, withcost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as theestimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrativeexpenses are reported as period costs and excluded from inventory cost.Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). TheCompany records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fairvalue of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements withthe same counterparty. (See Note 8).Deferred Financing Costs: The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying thePresentation of Debt Issuance Costs for its Term Loan Facility, Second Lien Notes, and the Unsecured Notes and includes the costs for issuing debt includingissuance discounts, as a direct deduction from the carrying amount of the related debt liability. Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurementof Debt Issuance Costs Associated with Line of Credit Arrangements for its Revolving Credit Facility and includes the costs related to the issuance of theRevolving Credit Facility in Other assets on the Consolidated Balance Sheets.64Table of Contents Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis andoperating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in theyears in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates isrecognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “morelikely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a taxposition only after determining that the relevant tax authority would more likely than not sustain the position following an audit.Warrants: On December 21, 2018, in connection with the consummation of the Exchange Transaction, the Company issued 10,919,499 new Warrants.The Warrants are initially exercisable for one common share of the Company, no par value, at an initial exercise price of $0.01 per Warrant (the “WarrantExercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the Common Shares is at least $2.50 perCommon Share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at theoption of the holders thereof from the December 21, 2018 until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holdersof such Warrants to purchase Common Shares will terminate. Under the guidance in FASB ASC 815, the Warrants do not meet the definition of a derivative.The Warrants are classified as equity and recorded at fair value as of the date of issuance on the Company’s Consolidated Balance Sheets and no furtheradjustments to their valuation are made.Earnings Per Share: Basic earnings per share is computed by dividing net earnings (attributable to common stockholders by the weighted averagenumber of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common sharesoutstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.In conjunction with our emergence from chapter 11 proceedings, on April 12, 2017, the Company issued shares of New Equity to holders of ExistingCommon Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if ithad occurred as of the earliest period presented.Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculatingdiluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria aremet. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator usingthe treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. For the years ended December 31, 2018 and2017, the Company had 14.2 million and 3.9 million, respectively, of contingently issuable shares that are not included in the diluted earnings per sharedenominator. There were no contingently issuable shares outstanding for the year ended December 31, 2016. The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2018 2017 2016 Net income $85,207 $177,140 $56,151 Weighted average common shares outstanding during the period 196,964 163,824 79,996 Effect of dilutive instruments 577 152 367 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,541 163,976 80,363 Net income per common share — basic $0.43 $1.08 $0.70 Net income per common share — fully diluted $0.43 $1.08 $0.70 Number of shares not included in dilutive earnings per share that wouldhave been anti-dilutive because the exercise price was greater than theaverage market price of the common shares — — 749 Use of Estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates andassumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements,and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards madeto employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation –Stock Compensation.65Table of Contents Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which definesfair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement appliesunder other accounting topics that require or permit fair value measurements. See Note 9 for additional information.Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oiland gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of theestimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions inestimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing ofsettling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool.The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices.On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. SeeNote 2 for additional details and disclosures related to the Company’s adoption of this standard.Other revenues: Other revenues are comprised of fees paid to us by operators of the gas processing plants where our gas is processed in exchange forthe liquids removed from our production.Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in asubsequent period.Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financialstatement presentation. These reclassifications had no effect on the reported results of operations.Recent Accounting Pronouncements: Revenues from Contracts with Customers: In May 2014, the FASB issued ASU 2014-09, Revenue fromContracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versusAgent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): IdentifyingPerformance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specificguidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when ittransfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goodsor services.On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the“new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1,2018 due to the cumulative impact of adopting the new revenue standard, with the impact related to changing from the entitlements method to the salesmethod to account for wellhead imbalances. The comparative information has not been restated and continues to be reported under the accounting standardsfor those periods. See Note 2 for additional details related to the adoption of this standard.Stock Compensation: In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which isintended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation,to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation ofthis ASU did not have a material impact on the Company’s consolidated financial statements.Leases: In February 2016, the FASB established Topic 842, Leases, by issuing issued ASU 2016-02, Leases (“ASU No. 2016-02”), which requireslessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability onthe balance sheet for all leases. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expenserecognition in the income statement.On January 1, 2019, we adopted the new standard. A modified retrospective transition approach is required, applying the new standard to all leasesexisting at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative periodpresented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leasesalso apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financialstatements and provide the disclosures required by the new standard for the comparative periods. We adopted the new standard on January 1, 2019 and willuse the effective date as our date of initial application. Consequently, financial information will not be updated and the disclosures required under the newstandard will not be provided for dates and periods before January 1, 2019.66Table of Contents The new standard provides a number of optional practical expedients in transition. We expect to elect the ‘package of practical expedients’, whichpermits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We also expectto adopt the practical expedient pertaining to land easements. We do not expect to elect the use-of-hindsight.The new standard also provides practical expedients for an entity’s ongoing accounting. We expect to elect the short-term lease recognition exemptionfor all leases that qualify. For those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets orlease liabilities for existing short-term leases of those assets in transition. We will continue to evaluate the practical expedients related to lease and non-leasecomponents.We expect that this standard will have a material effect on our financial statements. While we continue to assess all of the effects of adoption, wecurrently believe the most significant effects relate to (1) the recognition of new ROU assets and lease liabilities on our balance sheet for our office andequipment operating leases; and (2) the requirement to provide significant new disclosures about our leasing activities. These ROU assets and liabilities arenot deemed to be debt within the definitions of our debt covenants.On adoption, we currently expect to recognize additional operating liabilities, with corresponding ROU assets of the same amount based on the presentvalue of the remaining minimum rental payments under current leasing standards for existing operating leases.67Table of Contents Derivatives: In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815) (“ASU No. 2017-12”), which makes significant changesto the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships;presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periodsbeginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12to have a material impact on its consolidated financial statements as the Company does not elect hedge accounting. Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework —Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair valuemeasurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein.Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements. 2.IMPACT OF ASC 606 ADOPTION – REVENUE RECOGNITIONIn accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for twelvemonths ended December 31, 2018 is as follows: For the Twelve Months Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $722,313 $722,365 $(52)Oil sales 153,534 153,534 — Other revenues 16,652 16,652 — Costs and expenses: Production taxes $93,322 $93,326 $(4)Gathering fees 89,806 89,812 (6) Net income: $85,207 $85,249 $(42) The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method. TheCompany evaluated the contracts for sales of oil and natural gas utilizing the principal versus agent indicators, noting no change in revenue recognitionresulted from the analysis. 68Table of Contents Revenue RecognitionRevenue from Contracts with CustomersSales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and theperformance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, amongother factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As aresult, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies.Natural gas salesWe sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with ourcustomers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or(iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point atthe net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes beingsold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in thetransaction price; thus, they are presented as expenses in the Consolidated Statement of Operations.Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes,provided they are in compliance with the terms of the joint operating agreements. The Company may act as an agent and market the other partners’ share ofthe natural gas production. If it does so, the Company is considered the agent and revenue continues to be recorded at the Company’s net revenue interest inthe production, and the portion related to partners’ interest is not recognized as revenue.Oil salesWe sell oil production at (a) the lease automatic custody transfer (“LACT”) meter for Wyoming condensate, (b) the tank battery for Utahwax/condensate, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i)an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of theproduct. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering feesare performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price;thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. In conjunction with the adoption of ASC 606, for the twelvemonths ended December 31, 2018, there was no change to the method used to recognize oil sales and there was no impact to the consolidated financialstatements for oil sales.Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. TheCompany may act as an agent and market the other partners’ share of the oil production. If it does so, the Company is considered the agent and revenue isrecorded at the Company’s net revenue interest in the production. Other revenuesOur other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred uponcompletion of the processing service. The Company is considered the principal, and revenue is recognized at the point in time that the control istransferred. In conjunction with the adoption of ASC 606, for the twelve months ended December 31, 2018, there was no change to the method used torecognize other processing revenues and there was no impact to the consolidated financial statements for other revenues.Production imbalancesPreviously, the Company elected to utilize the entitlements method to account for natural gas imbalances, which is no longer allowed under ASC606. In conjunction with the adoption of ASC 606, for the twelve months ended December 31, 2018, there was no material impact to the consolidatedfinancial statements due to this change in accounting for our production imbalances.Transaction price allocated to remaining performance obligationsA significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized thepractical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations ifthe performance obligation is part of a contract that has an original expected duration of one year or less.69Table of Contents For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states thatthe Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocatedentirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performanceobligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is notrequired.Contract balancesUnder our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment isunconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.Prior-period performance obligationsWe record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not be received for30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and theprice that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in themonth that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and anyidentified differences between our revenue estimates and actual revenue received historically have not been significant. For the twelve months endedDecember 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.3.ASSET RETIREMENT OBLIGATIONS:The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligationassociated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. Thefollowing table summarizes the activities for the Company’s asset retirement obligations for the years ended: December 31, 2018 2017 Asset retirement obligations at beginning of period $173,100 $157,173 Accretion expense 12,342 11,689 Liabilities incurred 3,558 8,174 Liabilities divested (1) (2) (9,372) (4,812)Liabilities acquired - 1,456 Liabilities settled (70) (598)Revisions of estimated liabilities (96) 18 Asset retirement obligations at end of period 179,462 173,100 Less: current asset retirement obligations (193) (263)Long-term asset retirement obligations (3) $179,269 $172,837 (1)During the year ended December 31, 2018, the Company divested certain non-core properties in Utah.(2)During the year ended December 31, 2017, the Company divested certain non-core properties in north-central Pennsylvania.(3)Included in Other long-term obligations in the Consolidated Balance Sheet. 4.OIL AND GAS PROPERTIES: December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $11,577,281 $11,215,563 Less: Accumulated depletion, depreciation and amortization (10,079,554) (9,890,495)Total Oil and gas properties, net 1,497,727 1,325,068 On a unit basis, DD&A was $0.74, $0.59 and $0.44 per Mcfe for the years ended December 31, 2018, 2017 and 2016, respectively.70Table of Contents 5.PROPERTY, PLANT AND EQUIPMENT: December 31, 2018 2017 Cost AccumulatedDepreciation Net BookValue Net BookValue Computer equipment 2,828 (2,209) 619 554 Office equipment 265 (200) 65 95 Leasehold improvements 264 (178) 86 120 Land 2,437 — 2,437 4,637 Production and other equipment 20,232 (11,804) 8,428 4,163 Property, plant and equipment, net $26,026 $(14,391) $11,635 $9,569 6.LONG TERM DEBT: December 31, 2018 Principal UnamortizedDeferredFinancing Costsand Discounts (1) UnamortizedPremium onExchangeTransaction Carrying Value Credit Agreement $104,000 $— $— $104,000 Term Loan, secured, due 2024 975,000 (26,874) — 948,126 Second Lien Notes, secured, due 2024 545,000 — 228,096 773,096 6.875% Unsecured Notes due 2022 195,035 (15,168) — 179,867 7.125% Unsecured Notes due 2025 225,000 (14,608) — 210,392 $2,044,035 $(56,650) $228,096 $2,215,481 Less: Current maturities 7,313 — — 7,313 Total Long-term debt $2,036,722 $(56,650) $228,096 $2,208,168 December 31, 2017 Principal UnamortizedDeferred FinancingCosts and Discounts(1) Carrying Value Credit Agreement $— $— $— Term Loan, secured, due 2024 975,000 (23,357) 951,643 6.875% Unsecured Notes due 2022 700,000 (19,084) 680,916 7.125% Unsecured Notes due 2025 500,000 (16,348) 483,652 $2,175,000 $(58,789) $2,116,211 Less: Current maturities — — — Total Long-term debt $2,175,000 $(58,789) $2,116,211 (1)Deferred financing costs related to the Revolving Credit Facility are reported within Other assets on the consolidated balance sheet, rather than asa reduction of the carrying amount of long-term debt. Aggregate maturities of debt at December 31, 2019 $7,313 2020 $9,750 2021 $9,750 2022 $308,785 2023 $9,750 Beyond 5 years $1,698,687 Total $2,044,035 71Table of Contents Ultra Resources, Inc.Credit Agreement. On April 12, 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (the “Credit Agreement”) with the Companyand UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the otherlenders party thereto (collectively, the “RBL Lenders”) from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) subjectto a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (asdefined below). In September 2018, the borrowing base was reduced from $1.4 million to $1.3 billion in connection with the semi-annual determination, with$975.0 million allocated to the Company’s Term Loan Facility (as defined below) and $325.0 million allocated to the Revolving Credit Facility.On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into theThird Amendment to the Credit Agreement (the “Third Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to theThird Amendment, the parties agreed, among other things, to amend the Credit Agreement to permit the issuance of the Second Lien Notes and the ExchangeTransaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to: •increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Credit Agreement); •removing the ability to create, invest in and utilize unrestricted subsidiaries that are not guarantors under the Revolving Credit Facility; •further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as morethoroughly described in the Third Amendment; and •providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the ThirdAmendment.In conjunction with the Exchange Transaction, the Third Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications andExtinguishments specifically for modifications to or exchanges of revolving-debt arrangements. Based on the guidance, the unamortized deferred costs, anyfees paid to the creditor, and any third-party costs associated with Third Amendment, which were incurred as part of the Exchange Transaction, will bedeferred and amortized over the term of the Credit Agreement since the borrowing capacity did not change. Deferred financing costs, including the new costsincurred as part of the Exchange Transaction, are recorded as Other assets on the Consolidated Balance Sheets in accordance with ASU No. 2015-15.On February 14, 2019, Ultra Resources entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment”) with the RBL AdministrativeAgent and the RBL Lenders party thereto. Pursuant to the Fourth Amendment, the borrowing base was reaffirmed at $1.3 billion.The Fourth Amendment also revises certain covenants and other provisions of the Credit Agreement, including, but not limited to: •Amending the Consolidated Net Leverage Ratio financial covenant as described below. In addition, the consolidated net debt component of theconsolidated net leverage ratio may be reduced upon receipt of proceeds from the make-whole litigation as described in Note 12; •Revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that representan accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to seniormanagement changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debtrestructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of anaccrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certainnoncash charges that Ultra Resources chose to add back (as described in clause (i)); and •Amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, current requiredamortization payments under the Term Loan Agreement.At December 31, 2018, Ultra Resources had $104.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments underthe Revolving Credit Facility of $325.0 million, and a borrowing base of $1.3 billion. Given the Revolving Credit Agreement was amended in February2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is October 1, 2019.72Table of Contents The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of thecommitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary Londoninterbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of anyfiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwiseapply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The RevolvingCredit Facility loans mature on January 12, 2022.Under the Fourth Amendment, Ultra Resources is required to maintain (i) a minimum interest coverage ratio of 2.50 to 1.00; (ii) a current ratio,including the unused portion of the Revolving Credit Facility of a minimum of 1.00 to 1.00; and (iii) after the Company has obtained investment graderating an asset coverage ratio of 1.50 to 1.00. In addition, as of the last day of (i) the fiscal quarter ending December 31, 2018, Ultra Resources will not permitthe consolidated net leverage ratio to exceed 4.50 to 1.0, (ii) each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019, UltraResources will not permit the consolidated net leverage ratio to exceed 4.75 to 1.0, (iii) each fiscal quarter ending during the period from September 30, 2019through June 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.90 to 1.0, (iv) the fiscal quarter ending September 30,2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.50 to 1.0, and (v) the fiscal quarter ending December 31, 2020 and eachother fiscal quarter end thereafter, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.25 to 1.0.As of December 31, 2018, Ultra Resources’ consolidated net leverage ratio was 3.95 to 1.00 and it was in compliance with each of its debt covenantsunder the Credit Agreement.Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, theCompany is required to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its proved developed producing (“PDP”) reserves;and during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of thequarterly projected volumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedgingrequirement.Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon aborrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees.The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws(including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports,maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions,fundamental changes, restricted payments, hedging requirements and other customary covenants.The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not complywith the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of allamounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated.Term Loan. On April 12, 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement (the “Term Loan Agreement”) withthe Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent (the “Term Loan Administrative Agent”), andthe other lenders party thereto (collectively, the “Term Loan Lenders”), providing for senior secured first lien term loans for an aggregate amount of $800.0million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawnimmediately after the funding of the initial term loan. In September 2017, the Company closed an incremental senior secured term loan offering of $175.0million, increasing total borrowings under the Term Loan Agreement to $975.0 million (the “Term Loan Facility”). As part of the Term Loan Agreement,Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in deferred financing costs. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into theFirst Amendment to the Term Loan Agreement (the “Term Loan Amendment”) with the Term Loan Administrative Agent and the Term Loan Lenders partythereto. Pursuant to the Term Loan Amendment, the parties agreed, among other things, to amend the Term Loan Agreement to permit the issuance of theSecond Lien Notes and the Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payablein cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to: •introducing call protection of 102% until the first anniversary of the Exchange Transaction and 101% until the second anniversary of theExchange Transaction (defined below); •introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility asmore thoroughly described in the Term Loan Amendment;73Table of Contents •deleting the ability to increase commitments under the Term Loan; •increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement); •removing the ability to create, invest in and utilize unrestricted subsidiaries; •further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as morethoroughly described in the Term Loan Amendment; and •providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term LoanAmendment.At December 31, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Facility.Following the Exchange Transaction, the Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable in-kind (“PIK”) uponelection by Ultra Resources. The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregateprincipal amount beginning on June 30, 2019. The Term Loan Facility matures on April 12, 2024.In conjunction with the Exchange Transaction, the Term Loan Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications andExtinguishments. The instrument was determined to not be substantially different and debt modification accounting was applied as this transaction was not atroubled debt restructuring (“TDR”). As a result, no gain or loss was recorded. New fees paid to the Term Loan Lenders totaled $7.2 million and are includedas deferred financing costs, which is direct deduction from the carrying amount of the Term Loan.The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, withoutlimitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss ofUltra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement ifthe asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term LoanFacility.The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (includingenvironmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenanceand operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes,restricted payments and other customary covenants. At December 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the TermLoan Agreement.The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not complywith the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of allamounts outstanding under the Term Loan Agreement.Second Lien Notes. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources issued $545.0 millionaggregate principal amount of Second Lien Notes and entered into an Indenture, dated as of December 21, 2018 (the “Second Lien Notes Indenture”), amongUltra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”) andcollateral agent.In January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for$27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions. Such Second Lien Notes were issuedpursuant to the Second Lien Notes Indenture. The Company will evaluate the treatment of the follow-on exchanges under the same accounting literature usedin the Exchange Transaction.The Second Lien Notes will mature on July 12, 2024. Interest on the Second Lien Notes will accrue at (i) an annual rate of 9.00% payable in cash and(ii) an annual rate of 2.00% PIK. The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15,2019.The Second Lien Notes are senior secured obligations of Ultra Resources and rank senior in right of payment to all of its existing and future unsecuredsenior debt, to the extent of the value of the collateral pledged under the Second Lien Notes Indenture and related collateral arrangements, senior in right ofpayment to all of its future subordinated debt, and junior in right of payment to all of its existing and future secured debt of senior priority, to the extent ofthe value of the collateral pledged thereby. The Second Lien Notes are secured by second priority security interests in substantially all assets of theCompany. Payment by Ultra Resources of all amounts due on or in respect of the Second Lien Notes and the performance of Ultra Resources under theIndenture are initially guaranteed by the Company.74Table of Contents Prior to December 21, 2021, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principalamount of the Second Lien Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 111.000% of theprincipal amount of the Second Lien Notes, plus accrued and unpaid interest (including PIK interest), if any, to the date of redemption, if at least 65% of theoriginal principal amount of the Second Lien Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. Inaddition, before December 21, 2019, Ultra Resources may redeem all or a part of the Second Lien Notes at a redemption price equal to the sum of (i) theprincipal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest (including PIK interest), if any, to theredemption date. In addition, on or after December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at redemption prices(expressed as percentages of principal amount) equal to 105.500% for the twelve-month period beginning on December 21, 2021, 102.750% for the twelve-month period beginning December 21, 2022, and 100.000% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plusaccrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes.If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second LienNotes may require the Issuer to repurchase all or a portion of its Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount ofsuch Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase.The Second Lien Notes Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of itssubsidiaries to: (i) sell assets and subsidiary equity; (ii) incur or redeem indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v)pay cash dividends, (vi) change the nature of its business or operations, (vii) make certain types of investments, (ix) enter into agreements that restrictdistributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (x) consolidate, merge or transfer all or substantiallyall of the assets of the Company or any Restricted Subsidiary (as defined in the Second Lien Notes Indenture); and (xi) create unrestricted and foreignsubsidiaries. The covenants in the Second Lien Notes Indenture are subject to important exceptions and qualifications. Subject to conditions, the SecondLien Notes Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Second Lien Notes receiveinvestment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc.The Second Lien Notes Indenture contains customary events of default. Unless otherwise noted in the Second Lien Notes Indenture, upon a continuingevent of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to theCompany and the Trustee, may declare the Second Lien Notes immediately due and payable, except that an event of default resulting from entry into abankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) or groupof Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, will automaticallycause the Second Lien Notes to become due and payable.In conjunction with the Exchange Transaction, the portion of the senior Unsecured Notes which were exchanged for Second Lien Notes was accountedfor as a TDR. The Company evaluated the quantitative and qualitative factors in the accounting literature and concluded that concessions were granted as thefuture undiscounted cash flows of the Second Lien Notes was greater than the net carrying value of the senior Unsecured Notes. No gain is recognized, and aneffective interest rate is established based on the carrying value of the Second Lien Notes and revised cash flows. The amount of extinguished debt will beamortized over the remaining life of the Second Lien Notes using the effective interest method and recognized as a reduction to interest expense. As a result,our reported interest expense following the Exchange Transaction, will be significantly less than the contractual cash interest payments throughout the termof the Second Lien Notes.The Exchange Transaction for the Second Lien Notes resulted in recognition of $4.7 million in expenses for the year ended December 31, 2018.The exchanged debt resulted in a calculation of cancellation of debt income for tax purposes. Our current tax attributes are expected to offset anypotential cash tax impacts from the Exchange Transaction. For additional details on the Company’s income taxes, refer to Note 10.Senior Unsecured Notes. On April 12, 2017, Ultra Resources issued $700.0 million of its 2022 Notes and $500.0 million of its 2025 Notes and enteredinto an Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, asguarantors, and Wilmington Trust, National Association, as Trustee. The Unsecured Notes are treated as a single class of securities under the Unsecured NotesIndenture.On December 21, 2018, the Company completed the Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i)approximately $505 million aggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principalamount, or 55.0%, of the issued and outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes and (b) an aggregate of10,919,499 new warrants of the Company each entitling the holder thereof to purchase one common share of the Company. As a result of the ExchangeTransaction, at December 31, 2018, the aggregate principal amounts outstanding under the Unsecured Notes were approximately $195.0 million with respectto the 2022 Notes and $225.0 million with respect to the 2025 Notes.The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Noteswill mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the UnsecuredNotes from the issue date until maturity. 75Table of Contents On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources, the Company and its other subsidiaries, asguarantors, and the Trustee entered into the First Supplement Indenture to the Unsecured Indenture (the “Supplemental Indenture”). Pursuant to theSupplemental Indenture, the parties amended the Unsecured Indenture to, among other things, eliminate or amend substantially all of the restrictivecovenants contained in the Unsecured Indenture, other than those relating to the payment of principal and interest. The Supplemental Indenture is binding onall Unsecured Notes that remain outstanding.The Unsecured Notes Indenture contains customary events of default. Unless otherwise noted in the Unsecured Notes Indenture, upon a continuingevent of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, bynotice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entryinto a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Unsecured Notes Indenture) orgroup of Restricted Subsidiaries (as defined in the Unsecured Notes Indenture), that taken together would constitute a Significant Subsidiary, willautomatically cause the Unsecured Notes to become due and payable. 7.SHARE BASED COMPENSATION:Valuation and Expense Information Year Ended December 31, 2018 2017 2016 Total cost of share-based payment plans $15,639 $53,952 $8,013 Amounts capitalized in oil and gas properties and equipment $3,814 $13,975 $2,451 Amounts charged against income, before income tax benefit $11,825 $39,977 $5,562 Amount of related income tax benefit recognized in income before valuation allowances $2,483 $15,927 $2,216 Securities Authorized for Issuance Under Equity Compensation PlansAs of December 31, 2018, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance underthe Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury. Plan Category Number of SecuritiesRemaining Availablefor Future IssuanceUnder EquityCompensation Plans (000’s) Equity compensation plans approved by security holders 14,457 Equity compensation plans not approved by security holders n/a Total 14,457 Performance Share Plans:2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan was established by our board of directors (the“Board”) pursuant to which 7.5% of the equity of the Company (on a fully-diluted/fully distributed basis) is reserved for grants to be made from time-to-timeto the directors, officers, and other employees of the Company (the “Reserve”). During 2017, management incentive grants (the “Initial MIP Grants”) weremade to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants,including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals orexceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the InitialMIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volumeweighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, suchInitial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time. 76Table of Contents In June 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of theUltra Petroleum Corp. 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends andrestates the 2017 Stock Incentive Plan to, among other things: •provide that consultants, independent contractors and advisors are eligible to participate and receive equity awards in the A&R Stock IncentivePlan; •limit the aggregate incentive awards available to be granted to any outside director during a single calendar year to a maximum of $750,000; •revise the definition of a Change of Control to exclude a change in a majority of the members on the Board; •provide that, with respect to awards granted on or after June 8, 2018, no such awards will vest solely as a result of a Change of Control (as definedin the A&R Stock Incentive Plan) unless expressly provided otherwise in the applicable grant agreement or unless otherwise determined by theCommittee; and •make certain other changes related to revisions to the U.S. Internal Revenue Code.In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvestedportion of their Initial MIP Grants for new equity awards of time-based restricted stock units (the “2018 RSUs”) effective July 31, 2018 on a one-for-one basis.All 2018 RSUs are time-based awards and vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021. Under FASB ASC Topic 718,Compensation Cost – Stock Compensation (“FASB ASC 718”), the cancellation of an outstanding award of stock-based compensation followed by theissuance of a replacement award is treated as a modification of the original award. The equity award cancellations and subsequent new grants by theCompany were considered Type I, probable-to-probable modification. This type represents modifications where the award was likely to vest prior tomodification and is still likely to vest after modification. For these types of modifications, the fair value of the award is assessed both prior to modificationand after modification. If the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized overthe remaining vesting period. The incremental expense recognized from the modification was $0.6 million for the twelve months ended December 31, 2018.Long Term Incentive Awards. In 2018, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further alignthe interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company whenspecific corporate financial and operational goals are achieved. The awards cover a performance period of three years and includes time-based andperformance-based measures established by the Committee at the beginning of the three-year period.Stock-Based Compensation Cost: Market-Based Condition Awards. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’stotal equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is acomponent of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an awardthat is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impactof the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimatethe fair value of the awards that include a market condition.FASB ASC 718 requires the expense for an award of stock-based compensation that is subject to a market condition that can be attained at any pointduring the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and(b) award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution ofshare price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on whichthe market condition is satisfied. The duration is the period of time from the service inception date to the expected date of market condition satisfaction.Compensation expense is recognized regardless of whether the market condition is actually satisfied.Expense. For the year ended December 31, 2018, the Company recognized $11.8 million in pre-tax compensation expense, of which $10.9 millionrelated to the Initial MIP Grants. For the year ended December 31, 2017, the Company recognized $40.0 million in pre-tax compensation expense, of which$38.5 million related to the Initial MIP Grants. For the year ended December 31, 2016, the Company recognized $5.6 million in pre-tax compensationexpense, of which $4.7 million related to the Company’s 2015 and 2014 long-term incentive plan awards. The Company expects the total expenseassociated with the portion of the Initial MIP Grants that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $21.3million and the portion of the Initial MIP grants that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $19.6 million,respectively. 77Table of Contents 8.DERIVATIVE FINANCIAL INSTRUMENTS:Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realizedpricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas productionhave been volatile and unpredictable. Pricing volatility is expected to continue. The prices we receive for our production depend on many factors outside ofour control, including volatility in the differences between product prices at sales points and the applicable index price.The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty inthe Company’s forward cash flows supporting the Company’s capital investment program. These types of instruments may include fixed price swaps, costlesscollars, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedgedcommodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increasesin commodity prices above the fixed hedge prices.The Company’s Revolving Credit Facility requires the Company to hedge 65% of forecast proved producing natural gas production, based on its mostrecent reserve report for 18 months from the end of the given quarter. This requirement is in effect through September 30, 2019. After that time, therequirement decreases to 50% of the estimated proved producing forecast for natural gas through March 31, 2020. This means the Company may unwindhedges after September 30, 2019 at its discretion providing the Company remains hedged at the 50% level for natural gas. Additionally, the RevolvingCredit Facility limits the amount of hedging to 85% of forecast production for all products within a given quarter.Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liabilityand be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.The Company does not apply hedge accounting to any of its derivative instruments.Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on theConsolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements ofOperations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do notimpact operating cash flows on the Consolidated Statements of Cash Flows.Commodity Derivative Contracts: At December 31, 2018, the Company had the following open commodity derivative contracts to managecommodity price risk. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable to the counterparty. For thebasis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period.For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below thefloor on a notional quantity. The reference prices of these commodity derivative contracts are typically referenced to index prices published by independentthird parties. Type Index Total Volumes(in millions) Weighted Average Price Per Unit Fair Value -December 31, 2018Asset (Liability) Natural Gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 NYMEX-Henry Hub 185.9 $2.81 $(12,832)2020 NYMEX-Henry Hub 22.8 $2.76 $(4,506) Natural Gas basis swaps (Mmbtu) ($/Mmbtu) 2019 NW Rockies Basis Swap 105.9 $0.67 $(41,286) Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 NYMEX-WTI 1.4 $58.45 $15,143 2020 NYMEX-WTI 0.1 $60.05 $994 Type Index Total Volumes(in millions) WeightedAverageFloor Price WeightedAverageCeiling Price Fair Value -December 31, 2018Asset (Liability) Natural Gas collars 2020 NYMEX 9.1 $2.75 $3.19 $(346)78Table of Contents Subsequent to December 31, 2018, the Company entered into commodity derivative contracts to manage commodity price risk as detailed anddescribed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivativeinstruments in the Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016: For the Year Ended December 31, Commodity Derivatives: 2018 2017 2016 Realized gain (loss) on commodity derivatives-natural gas (1) $(77,031) $11,446 $— Realized gain (loss) on commodity derivatives-crude oil(1) (8,382) — — Unrealized gain (loss) on commodity derivatives (1) (59,799) 16,966 — Total gain (loss) on commodity derivatives $(145,212) $28,412 $— (1)Included in Gain (loss) on commodity derivatives in the Consolidated Statements of Operations. 9.FAIR VALUE MEASUREMENTS:As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishesa three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, includingquoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other thanquoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instrumentscategorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market dataobtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). Level 1 Level 2 Level 3 Total Assets: Current derivative asset $— $23,374 $— $23,374 Long-term derivative asset (1) — 1,203 — 1,203 Total derivative instruments $— $24,577 $— $24,577 Liabilities: Current derivative liability $— $62,350 $— $62,350 Long-term derivative liability (2) — 5,060 — 5,060 Total derivative instruments $— $67,410 $— $67,410 (1)Included in Other assets in the Consolidated Balance Sheet. (2)Included in Other long-term obligations in the Consolidated Balance Sheet. Assets and Liabilities Measured on a Non-Recurring BasisThe Company uses fair value to determine the value of its asset retirement obligations. The inputs used to determine such fair value under the expectedpresent value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation andsimilar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs.79Table of Contents Fair Value of Financial InstrumentsThe estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. Thecarrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fairvalue due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value becausethe interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixedrate debt and the fair values presented in the tables below reflect original maturity dates for each of the debt instruments. The inputs utilized to estimate thefair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825,Financial Instruments, and does not impact our financial position, results of operations or cash flows. For the Year Ended December 31, 2018 2017 Principal EstimatedFair Value Principal EstimatedFair Value Credit Agreement, secured $104,000 $104,000 $— $— Term Loan, secured due 2024 975,000 858,000 975,000 975,000 Second Lien Notes, secured due 2024 (1) 545,000 395,125 — — 6.875% Senior, unsecured Notes, due 2022 195,035 68,262 700,000 701,750 7.125% Senior, unsecured Notes, due 2025 225,000 69,750 500,000 505,000 Total debt $2,044,035 $1,495,137 $2,175,000 $2,181,750 (1)The fair value on Second Lien Notes is priced as of January 8, 2019, the first available trade date. 10.INCOME TAXES:Income before income tax benefit is as follows: Year Ended December 31, 2018 2017 2016 United States $86,242 $(197,136) $134,959 Foreign (593) 360,982 (79,462)Total $85,649 $163,846 $55,497 The consolidated income tax provision (benefit) is comprised of the following: Year Ended December 31, 2018 2017 2016 Current tax: U.S. federal, state and local $433 $(13,296) $(72)Foreign 9 2 (583)Total current tax provision (benefit) 442 (13,294) (655)Deferred tax: Foreign — — 1 Total deferred tax expense — — 1 Total income tax provision (benefit) $442 $(13,294) $(654)80Table of Contents The income tax provision (benefit) from operations differs from the amount that would be computed by applying the U.S. federal income tax rate of21% to pretax income as a result of the following: Year Ended December 31, 2018 2017 2016 Income tax provision computed at the U.S. statutory rate $17,986 $57,346 $19,424 State income tax (benefit) provision net of federal effect — (25,519) (2,335)Valuation allowance (30,723) (562,491) (31,083)Tax effect of rate change — 463,113 — Sale of non-core assets 5,863 130,552 — Foreign rate differential (36) (3,150) 17,388 Reorganization items 216 (89,327) — Equity compensation 2,689 10,778 1,599 Other, net 4,447 5,404 (5,647)Total income tax provision (benefit) $442 $(13,294) $(654) The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows: December 31, 2018 2017 Deferred tax assets: Property and equipment 33,953 181,524 Deferred gain 19,874 22,256 U.S. federal tax credit carryforwards 512 987 U.S. interest carryforwards 5,931 — U.S. net operating loss carryforwards 462,401 450,623 U.S. state net operating loss carryforwards — 4,038 Non-U.S. net operating loss carryforwards 7,048 6,556 Asset retirement obligations 37,687 36,624 Derivative instruments, net 8,995 — Debt financing 92,706 — Incentive compensation 5,370 6,585 Other, net 2,148 1,723 Total deferred tax assets, gross 676,625 710,916 Valuation allowance (676,625) (707,348)Net deferred tax assets $— $3,568 Deferred tax liabilities: Derivative instruments, net — 3,568 Net tax liabilities $— $3,568 Net tax asset $— $— In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred taxassets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods inwhich the temporary differences become deductible or before the attributes expire unused. Among other items, management considers the scheduled reversalof deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies.At December 31, 2018 and 2017, the Company recorded a valuation allowance against certain deferred tax assets of $0.7 billion and $0.7 billion,respectively. Some or all of this valuation allowance may be reversed in future periods if future taxable income of the appropriate character is available torecognize certain deferred tax assets.81Table of Contents The Company has a U.S. federal tax net operating loss carryforward of $2.2 billion as of December 31, 2018, which will be carried forward to offsettaxable income generated in future years, and if unutilized, will expire between 2033 and 2037 for net operating losses generated in tax years 2017 andearlier. Federal net operating losses generated in tax years 2018 and later carry forward indefinitely and are limited to 80% of taxable income, if utilized. TheCompany has immaterial Canadian Federal and Provincial and U.S. State tax net operating loss carry forwards that it does not expect to utilize before theyexpire, as the Company has minimal or no activity in these jurisdictions. The ownership change that occurred as a result of the Company’s chapter 11restructuring did not significantly impair the ability to utilize the net operating loss carryforwards to offset future taxable income. Without regard to therecorded valuation allowance, if the Company experiences an additional ownership change as determined under Section 382 of the Internal Revenue Code,our ability to utilize our substantial net operating loss carryforwards and other tax attributes may be limited, if we can use them at all.The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related toaccounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2018.Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in theConsolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits.The Company files a consolidated federal income tax return in the United States, as well as an income tax return in Canada. With certain exceptions,the income tax years 2015 through 2018 remain open to examination by the major taxing jurisdictions in which the Company has business activity. TheCompany has been notified that Canada intends to audit tax years 2015 and 2016. Management does not expect the results of the audit to materially impactthe Company’s financial statements.The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. It is not practical toestimate the amount of unrecognized deferred tax liability related to undistributed foreign earnings at this time. No provision for Canadian income taxesand/or withholding taxes has been provided thereon.On December 22, 2017, the Tax Act was enacted into law. The new legislation decreased the U.S. corporate federal income tax rate from 35% to 21%effective January 1, 2018. The Company did not have any impact on recorded deferred tax balances as the re-measurement of net deferred tax assets was offsetby a change in the valuation allowance. The Tax Act also included a number of other provisions including the elimination of loss carrybacks and limitationson the use of future loss carryforwards, repeal of the “alternative minimum tax” regime, limitations on the deductibility of certain expenses, including netinterest expense, and changes in the way capital costs are recovered. These provisions are not expected to have an immediate effect on the Company. TheTax Act did not make significant changes to the Company’s ability to deduct intangible development costs or depletion. The Company’s significant netoperating loss carryforwards generated in 2017 and before are grandfathered under the provisions of the Tax Act and should not be subject to the newlimitations imposed by the Tax Act. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue to be issued at times. The Company will continue tomonitor these new regulations and analyze their applicability and impact on the Company. The SAB 118 period expired, and no adjustments were made tothe provisional accounting adjustments reporting in 2017.11.EMPLOYEE BENEFITS:The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for itsemployees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% ofcompensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contributionwas $2.5 million, $2.4 million and $2.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.12.COMMITMENTS AND CONTINGENCIES:LeasesPinedale LGSDuring December 2012, the Company sold a system of pipelines and central gathering facilities (the “Pinedale LGS”) and certain associated realproperty rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Pinedale Lease Agreement”) relating tothe use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75%of the then remaining useful life of the Pinedale LGS at the sole discretion of the Company. Annual rent for the initial term under the Pinedale LeaseAgreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase when certain volume thresholds areexceeded. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Pinedale Lease Agreement willtotal approximately $195.7 million.82Table of Contents All of the Company’s lease obligations are related to leases that are classified as operating leases under ASC 840. These leases contain certainprovisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in itslease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.Office space leaseThe Company maintains office space in Colorado and Wyoming, with total remaining commitments for office leases of $3.9 million at December 31,2018; ($1.2 million in 2019; $1.1 million in 2020; $1 million in 2021; and $0.6 million in 2022.During the years ended December 31, 2018, 2017 and 2016, the Company recognized expense associated with its office leases in the amount of$1.6 million, $1.6 million, and $1.5 million, respectively.Delivery CommitmentsWith respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas toits customers. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all ofthese commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities orcurtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agenciesor any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Part I. Item 1A.“Risk Factors.” If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchasevolumes in the market or make other arrangements to satisfy the commitments.Litigation MattersPending Claims – Ultra Resources Indebtedness ClaimsThe Plan provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise beensatisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Annual Report on Form 10-K, the claims resolution processassociated with chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time.Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, manyholders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaidprepetition interest dates, unpaid post-petition interest (including interest at the default rates under the debt agreements), make-whole amounts, and other feesand obligations allegedly arising under the debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordancewith the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to thelimited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including withrespect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). Inconnection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establishand fund a $400.0 million reserve account after the Company’s emergence from bankruptcy, pending resolution of make-whole and postpetition interestclaims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of theUltra Resources’ indebtedness for certain make-whole amounts and post-petition interest at the default rates provided for in the debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. OnOctober 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicableparties. Pursuant to the order, on October 12, 2017, $399.0 million was distributed from the Reserve Fund to the parties asserting the make-whole andpostpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. Thedisbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above, which areincluded in reorganization items in the Consolidated Statements of Operations as of December 31, 2017, and $175.2 million representing the postpetitioninterest at the default rate, as described above, which is included in interest expense in the Consolidated Statements of Operations as of December 31,2017. The Company appealed the court order denying its objections to these claims to the United States Court of Appeals for the Fifth Circuit (the“Appellate Court”).During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certainclaims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between theClaimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to theCompany.83Table of Contents On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to theasserted make-whole and post-petition interest claims and remanding the matter and those determinations to the Bankruptcy Court for furtherreconsideration. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimate dispositionof these matters at this time.RoyaltiesOn April 19, 2016, the Company received a preliminary determination notice from the Office of Natural Resources Revenue (“ONRR”) asserting thatthe Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in thedetermination of royalties owed under Federal oil and gas leases for the 2010, 2011, and 2012 time periods (the “Audit Period”). ONRR also filed a proof ofclaim in our bankruptcy proceedings asserting approximately $35.1 million in claims related to these matters. We disputed the preliminary determination andthe proof of claim. We notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice andthe Company continues to believe that natural gas sold during this period was in marketable condition and, therefore, no disallowances were necessary in thecalculation of royalties. This claim could ultimately result in us being required to pay additional royalties to ONRR with respect to the Audit Period as wellas additional royalties in respect of the years following the Audit Period. The Company is not able to determine the likelihood or range of any additionalroyalties or, if and when assessed, whether such amounts would be material.Oil Sales ContractOn April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) theCompany had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contractwas terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMTfiled a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and onDecember 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of the contract by SPMT during theprepetition period (as amended, the “Sunoco Adversary”). In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim formatters addressed in its proof of claim. On October 16, 2018, the Company reached a settlement agreement with SPMT. Under the terms of the agreement,the Company will pay SPMT a total of $2.0 million, of which $1.0 million was paid as of December 31, 2018. Other ClaimsThe Company is party to disputes with respect to overriding royalty interests in certain of our operated leases in Pinedale, Wyoming. At this time, nodetermination of the outcome of these claims can be made, and as no damage claim amount has been asserted by the claimants, we cannot reasonablyestimate the potential impact of these claims. We are defending these cases vigorously, and expect these claims to be resolved in our chapter 11 proceedings.The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine theultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a materialadverse effect on the Company’s financial position or results of operations.13.CONCENTRATION OF CREDIT RISK:The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivativecontracts associated with the Company’s hedging program. The Company’s revenues related to natural gas and oil sales are derived principally from a diversegroup of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financialinstitutions and end-users in various industries.Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas.Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to theCompany is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gasestablished in those contracts is less than the prevailing market price of natural gas, from time to time.The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas,condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to makingany sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter ofcredit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlementsat December 31, 2018.A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2018, theCompany had no single customer that represented more than 10% of its total revenues.84Table of Contents 14.2016/2017 CHAPTER 11 PROCEEDINGSVoluntary Reorganization Under Chapter 11 and Ability to Continue as a Going ConcernOn April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, “the Debtors”) filed voluntary petitions under chapter 11 oftitle 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 caseswere jointly administered under the caption In re Ultra Petroleum Corp., et al, (Case No. 16-32202 (MI). On March 14, 2017, the Bankruptcy Courtconfirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”), and on April 12, 2017 (the “Effective Date”), we emergedfrom bankruptcy.Plan of ReorganizationPursuant to the Plan, the significant transactions that occurred upon our emergence from chapter 11 proceedings were as follows: •On November 21, 2016, we entered into a Plan Support Agreement (as amended, the “PSA”) with certain holders of the Company’s prepetitionindebtedness and outstanding common stock as well as a Backstop Commitment Agreement (“BCA”). Pursuant to the BCA, we agreed toconduct a rights offering for new common stock in the Company to be issued upon the effectiveness of the Plan for an aggregate purchase priceof $580.0 million (the “Rights Offering”). •On February 8, 2017, we entered into a commitment letter with Barclays Bank PLC (“Barclays”) (as amended, the “Commitment Letter”)pursuant to which, in connection with the consummation of the Plan, Barclays agreed to provide us with secured and unsecured financings in anaggregate amount of up to $2.4 billion (the “Debt Financings”). •On the Effective Date, the principal obligations outstanding of $999.0 million under the prepetition credit agreement and $1.46 billion under theprepetition senior notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under theprepetition credit agreement and the prepetition senior notes were cancelled and extinguished as provided in the Plan. •On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 millionrelated to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full, each holder of a claim related to the 2018 Notesand the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligationsunder the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan. •On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.Fresh Start AccountingWe were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because thereorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims. Bankruptcy Claims Resolution ProcessThe claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in thefuture, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetitionclaims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcyproceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessarywith respect to claims we believe should be disallowed.Costs of ReorganizationDuring 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about thecosts of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.85Table of Contents The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the yearsended December 31, 2017 and 2016: For the Twelve Months EndedDecember 31, 2017 2016 Professional fees $(66,529) $(11,781)Gains (losses) (1) 431,107 — Deferred financing costs — (18,742)Contract settlements — (17,350)Make-whole fees (223,838) — Other (2) 167 370 Total Reorganization items, net $140,907 $(47,503) (1)Gains (losses) represent the net gain on the debt to equity exchange related to the Company’s prepetition senior notes.(2)Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.15.SUBSEQUENT EVENTS:The Company has evaluated the period subsequent to December 31, 2018 for events that did not exist at the balance sheet date but arose after that dateand determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forthbelow:2019 Debt ExchangesAs previously noted, in January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principalamount of 2022 Notes for $27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions. Such SecondLien Notes were issued pursuant to the Second Lien Notes Indenture.Make-Whole and Postpetition Interest ClaimsAs previously disclosed, during the Company’s bankruptcy proceedings, many holders of the Company’s prepetition indebtedness filed proofs of claimwith the Bankruptcy Court, asserting various claims against the Company, including claims for unpaid postpetition interest (including interest at the defaultrates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements.The Company disputed the claims made by the holders of Company’s prepetition indebtedness for certain make-whole amounts and postpetition interest atthe default rates provided for in the prepetition debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to thepending make-whole and postpetition interest claims. Further, on October 6, 2017, the Bankruptcy Court entered an order requiring the Company todistribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, the Company distributed $399.0million from a $400.0 million reserve fund set up in connection with its emergence from chapter 11 proceedings to the parties asserting the make-whole andpostpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. Thedisbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2million representing postpetition interest at the default rate.During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certainclaims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between theClaimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to theCompany.On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to theasserted make-whole and postpetition interest claims and remanding the matter and those determinations to the Bankruptcy Court for furtherreconsideration. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimatedisposition of these matters at this time.Revolving Credit Facility AmendmentAs described in Note 6, Ultra Resources entered into a Fourth Amendment to Credit Agreement with the Agent and the Lenders party thereto onFebruary 14, 2019. Pursuant to the Fourth Amendment, the Borrowing Base was reaffirmed at $1.3 billion for the spring 2019 period, providing $325 millionof availability to the Company as a result of the semi-annual borrowing base redetermination. The next scheduled semi-annual borrowing baseredetermination is scheduled for the fall of 2019.86Table of Contents The Fourth Amendment also revises certain covenants and other provisions of the Credit Agreement, including, but not limited to: •amending the Consolidated Net Leverage Ratio financial covenant to provide that, as of the last day of (i) the fiscal quarter ending December 31,2018, Ultra Resources will not permit the Consolidated Net Leverage Ratio (as defined in the Credit Agreement) to exceed 4.50 to 1.0, (ii) eachfiscal quarter ending during the period from March 31, 2019 through June 30, 2019, Ultra Resources will not permit the Consolidated NetLeverage Ratio to exceed 4.75 to 1.0, (iii) each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020, UltraResources will not permit the Consolidated Net Leverage Ratio to exceed 4.90 to 1.0, (iv) the fiscal quarter ending September 30, 2020, UltraResources will not permit the Consolidated Net Leverage Ratio to exceed 4.5 to 1.0, and (v) the fiscal quarter ending December 31, 2020 andeach other fiscal quarter end thereafter, Ultra Resources will not permit the Consolidated Net Leverage Ratio to exceed 4.25 to 1.0. In addition,the consolidated net debt component of the Consolidated Net Leverage Ratio may be reduced if, among other things, any Credit Party (asdefined in the Credit Agreement) receives certain settlement proceeds; •revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that representan accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to seniormanagement changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debtrestructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of anaccrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certainnoncash charges that Ultra Resources chose to add back (as described in clause (i)); and •amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, current requiredamortization payments under the Term Loan Credit Agreement (as defined in the Credit Agreement).16.SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 2018 1stQuarter 2ndQuarter 3rdQuarter 4thQuarter Total Operating revenues $225,374 $190,138 $203,776 $273,211 $892,499 Operating expenses 137,686 127,679 126,872 145,506 537,743 Other income (expense), net: Interest expense (35,837) (37,715) (38,382) (36,382) (148,316)Loss on commodity derivatives (6,530) (47,271) (21,804) (69,607) (145,212)Contract settlement — — (2,676) 15,332 12,656 Other income (expense), net 2,606 1,981 4,521 2,657 11,765 Total other (expense) income, net (39,761) (83,005) (58,341) (88,000) (269,107)Income (loss) before income tax provision (benefit) 47,927 (20,546) 18,563 39,705 85,649 Income tax provision (benefit) 434 9 — (1) 442 Net (loss) income $47,493 $(20,555) $18,563 $39,706 $85,207 Net income (loss) per common share — basic $0.24 $(0.10) $0.09 $0.20 $0.43 Net income (loss) per common share — fully diluted $0.24 $(0.10) $0.09 $0.20 $0.4387Table of Contents 2017 1stQuarter 2ndQuarter 3rdQuarter 4thQuarter Total Operating revenues $220,958 $212,657 $217,631 $240,627 $891,873 Operating expenses 104,227 134,393 122,394 132,574 493,588 Other income (expense), net: Interest expense (85,447) (29,425) (210,107) (36,388) (361,367)Gain (loss) on commodity derivatives (13,218) 20,717 4,650 16,263 28,412 Contract settlement (52,707) — — — (52,707)Other income, net 2,491 2,665 2,730 2,430 10,316 Total other (expense) income, net (148,881) (6,043) (202,727) (17,695) (375,346)Reorganization items, net (57,546) 426,816 (227,123) (1,240) 140,907 Income (loss) before income tax (benefit) provision (89,696) 499,037 (334,613) 89,118 163,846 Income tax provision (benefit) 2 — (6,886) (6,410) (13,294)Net (loss) income $(89,698) $499,037 $(327,727) $95,528 $177,140 Net income (loss) per common share — basic $(1.12) $2.76 $(1.67) $0.49 $1.08 Net income (loss) per common share — fully diluted $(1.12) $2.76 $(1.67) $0.49 $1.08 88Table of Contents 17.DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oiland Gas Reserve Estimation and Disclosures:OIL AND GAS RESERVES:Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gasreserves quantities and present values in compliance with the SEC’s regulations and GAAP. Our Director of Reservoir and Development is primarilyresponsible for overseeing the preparation of the Company’s reserve estimates and has a Bachelor of Science degree in Petroleum Engineering with over 14years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internalreview of assumptions used in the estimation.The estimates of proved reserves and future net revenue as of December 31, 2018, are based upon the use of technical and economic data including, butnot limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering andevaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy,that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules andregulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering andgeoscience data; therefore, these estimates necessarily represent only informed professional judgment.The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information maysignificantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accuratedetermination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. Fromtime to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics,new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does ithave any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates forall of the Company’s assets for the years ended December 31, 2018, 2017 and 2016 in this annual report.Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserveestimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performancedata, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the externalengineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report.The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry andfinancial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board ofProfessional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAIreserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No.125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over seven years of prior industry experience. He graduated fromgraduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientistin the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industryexperience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with aMaster of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in theStandards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both areproficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reservesdefinitions and guidelines.Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority oragency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve andother information, with the EIA.The following unaudited tables as of December 31, 2018, 2017 and 2016 reflect estimated quantities of proved oil and natural gas reserves for theCompany and the changes in total proved reserves as of December 31, 2018, 2017 and 2016. All such reserves were located in the Green River Basin inWyoming for the year ended December 31, 2018, in the Green River Basin in Wyoming and the Uinta Basin in Utah for the year ended December 31, 2017,and in the Green River Basin in Wyoming, the Appalachian Basin in Pennsylvania and the Uinta Basin in Utah for the year ended December 31, 2016.89Table of Contents ANALYSES OF CHANGES IN PROVEN RESERVES: United States Natural Gas(MMcf) Oil(MBbls) NGLs(MBbls) Reserves, December 31, 2015 2,336,280 22,175 9,840 Extensions, discoveries and additions 251,634 3,519 530 Sales — — — Acquisitions — — — Production (264,278) (2,912) — Revisions (2,023) (1,307) (467)Reserves, December 31, 2016 2,321,613 21,475 9,903 Extensions, discoveries and additions 50,312 1,117 — Sales (89,315) — — Acquisitions 22,400 153 — Production (260,009) (2,775) — Revisions 910,991 7,148 (9,832)Reserves, December 31, 2017 2,955,992 27,118 71 Extensions, discoveries and additions 85,180 1,086 — Sales (4,033) (3,573) (71)Acquisitions — — — Production (260,406) (2,442) — Revisions 145,100 1,256 — Reserves, December 31, 2018 2,921,833 23,445 — United States Natural Gas(MMcf) Oil(MBbls) NGLs(MBbls) Proved: Developed 2,336,280 22,175 9,840 Undeveloped — — — Total Proved — 2015 2,336,280 22,175 9,840 Developed 2,321,613 21,475 9,903 Undeveloped — — — Total Proved — 2016 2,321,613 21,475 9,903 Developed 2,261,289 21,652 71 Undeveloped 694,703 5,466 — Total Proved — 2017 2,955,992 27,118 71 Developed 2,243,956 17,876 — Undeveloped 677,877 5,569 — Total Proved — 2018 2,921,833 23,445 — Changes in proved developed reserves: During 2018, substantially all of the changes were attributable to wells drilled in 2018.Changes in proved undeveloped reserves: The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines forPUD development within five years. The Company annually reviews all PUDs to ensure an appropriate development plan exists. Development plan: The development plan underlying the Company’s proved undeveloped reserves, if any, adopted each year by senior management,is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data, and asset mix aresubject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions ofpreviously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of theCompany’s shareholders.90Table of Contents STANDARDIZED MEASURE:The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved reserves.Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’sproved reserves and future net revenues at December 31, 2018, 2017 and 2016 was $2.59, $2.59 and $2.07 per Mcf, respectively, for natural gas, and $63.49,$48.05 and $37.90 per barrel, respectively, for oil and condensate. In 2014, the Company acquired contracts related to NGLs providing an annual election toprocess NGLs beginning in 2017. In 2017, the Company renegotiated its existing gas processing contracts in Wyoming. The new gas processing contracts arekeep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include the NGL volumes in its reserves.The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the provedreserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to thedifference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating losscarryovers. As of December 31, 2018 2017 2016 Future cash inflows $9,195,725 $8,965,949 $5,812,234 Future production costs (3,337,779) (3,587,581) (2,665,082)Future development costs (1,133,103) (1,001,024) (355,923)Future income taxes (180,057) — — Future net cash flows 4,544,786 4,377,344 2,791,229 Discount at 10% (2,139,303) (1,993,016) (1,100,283)Standardized measure of discounted future net cash flows $2,405,483 $2,384,328 $1,690,946 The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties butwithout consideration of general and administrative and interest expenses.SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: December 31, 2018 2017 2016 Standardized measure, beginning $2,384,328 $1,690,946 $1,865,649 Net revisions of previous quantity estimates 160,405 840,505 (9,623) Extensions, discoveries and other changes 90,609 53,549 209,603 Sales of reserves in place (34,768) (83,887) — Acquisition of reserves — 21,903 — Changes in future development costs (235,205) (329,635) 11,556 Sales of oil and gas, net of production costs (593,134) (589,621) (454,725) Net change in prices and production costs 362,084 572,224 (72,939)Development costs incurred during the period that reduce future development costs 251,621 8,007 22,523 Accretion of discount 238,433 169,095 186,565 Net changes in production rates and other (189,017) 31,242 (67,663) Net change in income taxes (29,873) — — Aggregate changes 21,155 693,382 (174,703)Standardized measure, ending $2,405,483 $2,384,328 $1,690,946 91Table of Contents There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing ofdevelopment expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein representonly estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in anexact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation andjudgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimatemay justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimatelyrecovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, includinggeologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to greatuncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oiland natural gas prices have fluctuated widely.COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES: Years Ended December 31, 2018 2017 2016 United States Property Acquisitions: Unproved $1,468 $1,399 $983 Proved 1,090 9,147 — Exploration* 156,718 510,710 224,277 Development 266,905 35,934 44,300 Total $426,181 $557,190 $269,560 *Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: Years Ended December 31, 2018 2017 2016 United States Oil and gas revenue $892,499 $891,873 $721,091 Production expenses (299,365) (292,095) (266,366)Depletion and depreciation (204,255) (161,945) (125,121)Income tax benefit (expense) (2) (168,355) 83,112 Total $388,877 $269,478 $412,716 CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $11,577,281 $11,215,563 Less: accumulated depletion, depreciation and amortization (10,079,554) (9,890,495)Total Oil and gas properties, net $1,497,727 $1,325,068 18.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:Following are the financial statements of Ultra Petroleum Corp. (the “Parent Company”), which are included to provide additional information withrespect to the Parent Company’s results of operations, financial position and cash flows on a stand-alone basis:92Table of Contents CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2018 2017 2016 General and administrative expense $549 $428 $650 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) — (71,876) (26,590)Income (loss) from unconsolidated affiliates 85,809 (183,840) 157,450 Guarantee fee income — — 6,073 Other expense (44) 90 (64,888)Reorganization items, net — 433,196 (15,827)Income before income taxes 85,216 177,142 55,568 Income tax provision (benefit) 9 2 (583)Net income $85,207 $177,140 $56,151 CONDENSED BALANCE SHEET December 31, 2018 December 31, 2017 ASSETS Current Assets: Cash and cash equivalents $570 $803 Accounts receivable from related companies 29,939 29,940 Other current assets — — Total current assets 30,509 30,743 Other non-current assets — — Total assets $30,509 $30,743 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $— $21 Total current liabilities — 21 Advances from unconsolidated affiliates 1,079,131 1,185,359 Total liabilities 1,079,131 1,185,380 Total shareholders’ deficit (1,048,622) (1,154,637)Total liabilities and shareholders’ equity $30,509 $30,743 CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2018 2017 2016 Net cash (used in) operating activities $(234) $(2,206) $(21,309)Investing Activities: Investment in subsidiaries (3,293) (588,677) — Dividends received — — 24,089 Net cash (used in) provided by investing activities (3,293) (588,677) 24,089 Financing activities: Deferred financing costs — — — Shares issued 3,294 573,774 — Repurchased shares/net share settlements — 14,903 43 Shares re-issued from treasury — — (337)Net cash provided by (used in) financing activities 3,294 588,677 (294)(Decrease) increase in cash during the period (233) (2,206) 2,486 Cash and cash equivalents, beginning of period 803 3,009 523 Cash and cash equivalents, end of period $570 $803 $3,009 93Table of Contents Item 9.Change in and Disagreements with Accountants on Accounting and Financial Disclosures.None.Item 9A.Controls and Procedures.Management’s Report on Internal Control Over Financial ReportingManagement’s Report on Internal Control Over Financial Reporting is included on page 59 of this Form 10-K.Changes in Internal Control Over Financial ReportingThere were no changes in our internal control over financial reporting during the quarter ended December 31, 2018 that materially affected, or arereasonably likely to materially affect, our internal control over financial reporting.Evaluation of Effectiveness of Disclosure Controls and ProceduresUnder the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we evaluatedthe effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) promulgated under theExchange Act. Based on that evaluation, our chief executive officer and our chief financial officer concluded that our disclosure controls and procedureswere effective as of December 31, 2018, the end of the period covered by this report. The evaluation considered the procedures designed to ensure thatinformation required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reportedwithin the time periods specified in the SEC’s rules and forms and communicated to our management as appropriate to allow timely decisions regardingrequired disclosure.Item 9B.Other Information.None.94Table of Contents Part IIIItem 10.Directors, Executive Officers and Corporate GovernanceThe information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not laterthan 120 days after December 31, 2018.The Company has adopted a code of ethics that applies to the Company’s Chief Executive Officer, Chief Financial Officer and Chief AccountingOfficer. The full text of such code of ethics is posted on the Company’s website at www.ultrapetroleum.com, and is available free of charge in print to anyshareholder who requests it. Requests for copies should be addressed to the Secretary at 116 Inverness Drive East, Suite 400, Englewood, Colorado 80112.Item 11.Executive Compensation.The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not laterthan 120 days after December 31, 2018.Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not laterthan 120 days after December 31, 2018.Item 13.Certain Relationships, Related Transactions and Director Independence.The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not laterthan 120 days after December 31, 2018.Item 14.Principal Accounting Fees and Services.The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not laterthan 120 days after December 31, 2018.95Table of Contents Part IVItem 15. Exhibits, Financial Statement Schedules.The following documents are filed as part of this report:1. Financial Statements: See Part II, Item 8. “Financial Statements and Supplementary Data.”2. Financial Statement Schedules: Financial statement schedules required under SEC rules but not included in this Form 10-K are omittedbecause they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.3. Index to Exhibits. The following documents are included as exhibits to this Form 10-K. Exhibits incorporated by reference are duly noted assuch. ExhibitNumber Description 2.1 Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit A of the Order ConfirmingDebtors’ Second Amended Joint Chapter 11 Plan of Reorganization, filed as Exhibit 99.1 to the Current Report on Form 8-K filed by UltraPetroleum Corp. on March 16, 2017). 3.1 Articles of Reorganization of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Registration Statement on Form 8-Afiled by Ultra Petroleum Corp. on April 12, 2017). 3.2 Second Amended and Restated By-Law No. 1 of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 to the Current Report onForm 8-K filed by Ultra Petroleum Corp. on March 12, 2018). 4.1 Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra PetroleumCorp. on April 18, 2017). 4.2 Indenture dated April 12, 2017 among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto, andWilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed byUltra Petroleum Corp. on April 18, 2017). 4.3 First Supplemental Indenture dated as of December 21, 2018, to Indenture dated as of April 12, 2017, among Ultra Resources, Inc., UltraPetroleum Corp., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated byreference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018). 4.4 Indenture dated as of December 21, 2018, among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto, andWilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed byUltra Petroleum Corp. on December 26, 2018). 4.5 First Supplemental Indenture dated as of January 22, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp.,Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated byreference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on January 25, 2019). 4.6 Second Supplemental Indenture dated as of January 23, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp.,Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated byreference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on January 25, 2019). *4.7 Third Supplemental Indenture dated as of February 4, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp.,Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee. *4.8 Fourth Supplemental Indenture dated as of February 13, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp.,Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee.96Table of Contents *4.9 Fifth Supplemental Indenture dated as of February 15, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp.,Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee. 10.1 Senior Secured Term Loan Agreement dated as of April 12, 2017, among Ultra Petroleum Corp. and UP Energy Corporation, as parentguarantor, Ultra Resources Inc., as borrower, Barclays Bank PLC, as administrative agent and the lenders and other parties party thereto.(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017). 10.2 First Amendment to Senior Secured Term Loan Agreement dated as of December 28, 2018, among Ultra Resources Inc., as borrower, UltraPetroleum Corp. and UP Energy Corporation, as parent guarantor, Barclays Bank PLC, as administrative agent and the lenders and otherparties party thereto (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. onDecember 26, 2018). 10.3 Credit Agreement dated as of April 12, 2017, among Ultra Petroleum Corp. and UP Energy Corporation, as parent guarantor, UltraResources, Inc., as borrower, Bank of Montreal, as administrative agent, and the lenders and other parties party thereto. (incorporated byreference to Exhibit 10.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017). 10.4 First Amendment to Credit Agreement dated as of June 6, 2017, among Ultra Resources Inc., as borrower, Bank of Montreal, asadministrative agent, and the lenders and other parties party thereto (incorporated by reference to Exhibit 99.1 to the Current Report onForm 8-K filed by Ultra Petroleum Corp. on June 12, 2017). 10.5 Second Amendment to Credit Agreement dated as of April 19, 2018, among Ultra Resources, Inc. as borrower, Bank of Montreal, asadministrative agent, and each of the lenders and other parties party thereto (incorporated by reference to Exhibit 10.1 to the CurrentReport on Form 8-K filed by Ultra Petroleum Corp. on April 20, 2018). 10.6 Third Amendment to Credit Agreement dated as of December 21, 2018, among Ultra Resources, Inc. as borrower, Bank of Montreal, asadministrative agent, and each of the lenders and other parties party thereto (incorporated by reference to Exhibit 10.4 to the CurrentReport on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018). 10.7 Fourth Amendment to Credit Agreement dated as of February 14, 2019, among Ultra Resources, Inc. as borrower, Bank of Montreal, asadministrative agent, and each of the lenders and other parties party thereto (incorporated by reference to Exhibit 10.1 to the CurrentReport on Form 8-K filed by Ultra Petroleum Corp. on February 19, 2019). 10.8 Guaranty and Collateral Agreement dated as of April 12, 2017, among Ultra Petroleum Corp. and the other parties signatory thereto, asgrantors, and Bank of Montreal, as collateral agent. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed byUltra Petroleum Corp. on April 18, 2017). 10.9 Second Lien Guaranty and Collateral Agreement dated as of December 21, 2018, among Ultra Petroleum Corp. and the other partiessignatory thereto, as grantors, and Wilmington Trust, National Association, as collateral agent (incorporated by reference to Exhibit 10.3to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018). 10.10 First Lien/Second Lien Intercreditor Agreement dated as of December 21, 2018, by and among Bank of Montreal, as revolvingadministrative agent and as collateral agent for the senior secured parties, Barclays Bank PLC, as term loan administrative agent,Wilmington Trust, National Association, as the second lien collateral agent for the junior priority parties, Ultra Resources Inc., asborrower, and the other grantors party thereto (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by UltraPetroleum Corp. on December 26, 2018). 10.11 Registration Rights Agreement dated as of April 12, 2017 by and among Ultra Petroleum Corp. and the other parties signatory thereto(incorporated by reference to Exhibit 10.1 to the Registration Statement on Form 8-A filed by Ultra Petroleum Corp. on April 12, 2017). 10.12 Sale and Purchase Agreement dated October 18, 2013 between Axia Energy, LLC and UPL Three Rivers Holdings, LLC (incorporated byreference to Exhibit 1.1 of the Company’s Report on Form 8-K filed by Ultra Petroleum Corp. on October 24, 2013).97Table of Contents 10.13 Purchase and Sale Agreement dated August 13, 2014 between Ultra Petroleum Corp. and SWEPI LP (incorporated by reference fromExhibit 1.1 of the Company’s Report on Form 8-K filed by Ultra Petroleum Corp. on August 19, 2014). 10.14 Cooperation Agreement dated January 29, 2018 among Ultra Petroleum Corp. and Fir Tree Capital Management LP (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on January 30, 2018). 10.15 Exchange Agreement dated as of October 17, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., certain subsidiary guarantorsthereto and certain noteholders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra PetroleumCorp. on October 17, 2018). 10.16 Exchange Agreement dated as of December 17, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., certain subsidiary guarantorsthereto and certain noteholders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra PetroleumCorp. on December 26, 2018). 10.17 Warrant Agreement dated as of December 21, 2018, among Ultra Petroleum Corp., Computershare Inc. and Computershare Trust CompanyN.A., as warrant agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. onDecember 26, 2018). 10.18 Director Nomination Agreement dated as of December 21, 2018, among Ultra Petroleum Corp. and the holders of 9.00% Cash / 2.00% PIKSenior Secured Second Lien Notes due 2024 of Ultra Resources, Inc. signatory thereto (incorporated by reference to Exhibit 10.7 to theCurrent Report on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018). #10.19 Ultra Petroleum Corp. 2017 Stock Incentive Plan, as amended and restated June 8, 2018 (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K filed by Ultra Petroleum Corp. on June 14, 2018). #10.20 Ultra Petroleum Corp. Annual Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by UltraPetroleum Corp. on July 12, 2018). #10.21 Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8 filed byUltra Petroleum Corp. on April 12, 2017). #10.22 Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by UltraPetroleum Corp. on June 14, 2018). #10.23 Form of Restricted Stock Unit Grant Agreement (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed byUltra Petroleum Corp. on July 12, 2018). #10.24 Form of Restricted Stock Unit Grant Agreement (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed byUltra Petroleum Corp. on November 9, 2018). 10.25 First Amendment to Plan Support Agreement effective as of February 10, 2017, by and among Ultra Petroleum Corp. and the otherDebtors, on the one hand, and certain holders of common stock in Ultra Petroleum Corp. and debt securities issued by Ultra PetroleumCorp., on the other hand (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. onFebruary 15, 2017). #10.26 Employment Agreement of Michael D. Watford dated November 6, 2017 (incorporated by reference to Exhibit 10.8 to the QuarterlyReport on Form 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). #10.27 Employment Agreement of Garland R. Shaw dated November 6, 2017 (incorporated by reference to Exhibit 10.9 to the Quarterly Reporton Form 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). #10.28 Employment Agreement of Brad Johnson dated November 6, 2017 (incorporated by reference to Exhibit 10.10 to the Quarterly Report onForm 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). #10.29 Employment Agreement of Kent Rogers dated November 6, 2017 (incorporated by reference to Exhibit 10.11 to the Quarterly Report onForm 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). 98Table of Contents #10.30 Employment Agreement of Patrick Ash dated November 6, 2017 (incorporated by reference to Exhibit 10.12 to the Quarterly Report onForm 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). #10.31 Employment Agreement of Garrett B. Smith dated November 6, 2017 (incorporated by reference to Exhibit 10.13 to the Quarterly Reporton Form 10-Q filed by Ultra Petroleum Corp. on November 9, 2017). #10.32 Separation Agreement dated February 23, 2018 among Ultra Petroleum Corp. and Michael D. Watford (incorporated by reference toExhibit 10.17 to the Annual Report on Form 10-K filed by Ultra Petroleum Corp. on February 28, 2018). #10.33 Transition Agreement dated as of September 5, 2018, by and between Ultra Petroleum Corp. and Garland R. Shaw (incorporated byreference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed by Ultra Petroleum Corp. on November 8, 2018). #10.34 Transition Agreement dated as of September 5, 2018, by and between Ultra Petroleum Corp., and Garrett B. Spear-Smith (incorporated byreference to Exhibit 10.5 to the Quarterly Report on Form 10-Q filed by Ultra Petroleum Corp. on November 8, 2018). #10.35 Employment Agreement of Jerald J. “Jay” Stratton dated May 31, 2018 (incorporated by reference to Exhibit 10.1 to the Current Reporton Form 8-K filed by Ultra Petroleum Corp. on June 1, 2018). #10.36 Employment Agreement of Maree K. Delgado dated August 15, 2018 (incorporated by reference to Exhibit 10.6 to the Quarterly Reporton Form 10-Q filed by Ultra Petroleum Corp. on November 9, 2018). #*10.37 Employment Agreement of David W. Honeyfield dated as of November 5, 2018. #*10.38 Ultra Petroleum Corp. Directors Deferred Compensation Plan. *21.1 List of Subsidiaries of Ultra Petroleum Corp. *23.1 Consent of Netherland, Sewell & Associates, Inc. *23.2 Consent of Ernst & Young LLP. *31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. **32.1 Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. **32.2 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *99.1 Reserve Report Summary prepared by Netherland, Sewell & Associates, Inc. as of December 31, 2018. **101.INS XBRL Instance Document**101.SCH XBRL Taxonomy Extension Schema Document**101.CAL XBRL Taxonomy Extension Calculation Linkbase Document**101.LAB XBRL Taxonomy Extension Label Linkbase Document**101.PRE XBRL Taxonomy Extension Presentation Linkbase Document**101.DEF XBRL Taxonomy Extension Definition *Filed herewith**Furnished herewith#Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b). 99Table of Contents SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed onits behalf by the undersigned, thereunto duly authorized. ULTRA PETROLEUM CORP. By: /s/ Brad Johnson Name: Brad Johnson Title: President and Chief Executive Officer Date: March 7, 2019Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the dates indicated. Signature Title Date /s/ Brad JohnsonBrad Johnson President, Chief Executive Officer and Director (principal executive officer) March 7, 2019 /s/ David W. HoneyfieldDavid W. Honeyfield Senior Vice President and Chief Financial Officer(principal financial officer) March 7, 2019 /s/ Maree K. DelgadoMaree K. Delgado Vice President and Chief Accounting Officer(principal accounting officer) March 7, 2019 /s/ Evan LedermanEvan Lederman Chairman of the Board March 7, 2019 /s/ Neal P. GoldmanNeal P. Goldman Director March 7, 2019 /s/ Michael J. KeeffeMichael J. Keeffe Director March 7, 2019 /s/ Stephen J. McDanielStephen J. McDaniel Director March 7, 2019 /s/ Alan J. MintzAlan J. Mintz Director March 7, 2019 /s/ Edward A. Scoggins, Jr.Edward A. Scoggins, Jr. Director March 7, 2019 100Table of Contents Certain DefinitionsTerms used to describe quantities of oil and natural gas and marketing •Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. •Bcf — One billion cubic feet of natural gas. •Bcfe — One billion cubic feet of natural gas equivalent. •Tcfe — One trillion cubic feet of natural gas equivalent. •BOE — One barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas. •BTU — British Thermal Unit. •Condensate — An oil-like, liquid hydrocarbon which is produced in association with natural gas production that condenses from natural gas as itis produced and delivered into a separator or similar equipment prior to the delivery of such natural gas to the natural gas gathering pipelinesystem. •MBbl — One thousand barrels of crude oil or other liquid hydrocarbons. •Mcf — One thousand cubic feet of natural gas. •Mcfe — One thousand cubic feet of natural gas equivalent, converting oil, condensate or NGLs to natural gas at the ratio of one barrel of oil,condensate or NGLs to six Mcf of natural gas. •MMBbl — One million barrels of crude oil or other liquid hydrocarbons. •MMcf — One million cubic feet of natural gas. •MMBTU — One million British Thermal Units. •NGL or NGLs — Natural gas liquids, which are expressed in barrels.Terms used to describe the Company’s interests in wells and acreage •Completion — Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriateauthority that the well has been abandoned. •Dry Well — An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities tojustify completion as an oil or gas well. •Gross oil and natural gas wells or acres — The Company’s gross wells or gross acres represent the total number of wells or acres in which theCompany owns a working interest. •Net oil and natural gas wells or acres — Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that theCompany owns in such wells or acres represented by the underlying properties. •Prospect — A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible toproduce. •Undeveloped acreage — Acreage on which wells have not been drilled or completed to a point that would permit the production of economicquantities of oil or gas regardless of whether such acreage contains proved reserves.Terms used to assign a present value to the Company’s reserves •Standardized measure of discounted future net cash flows, after income taxes — The present value, discounted at 10%, of the after tax future netcash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and natural gasproduction attributable to the proved reserves estimated in its independent engineer’s reserve report for the oil and natural gas spot prices basedon the average price during the 12-month period before the ending date of the period covered by the report determined as an un-weighted,arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for energy content, quality and transportation.The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. Theassumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes, using ratesin effect on the date of the report, are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in thestandardized measure of the Company’s proved reserves. •Standardized measure of discounted future net cash flows before income taxes — The discounted present value of proved reserves is identical tothe standardized measure described above, except that estimated future income taxes are not deducted in calculating future net cash flows. TheCompany discloses the discounted present value without deducting estimated income taxes to provide what it believes is a more comparativebasis of its reserves to the producers who may have different income tax rates.101Table of Contents Terms used to classify the Company’s reserve quantitiesThe Securities and Exchange Commission (“SEC”) definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:Economically producible — A resource that generates revenue that exceeds (or is reasonably expected to exceed) costs of the operation.Estimated ultimate recovery — The sum of reserves remaining as of a given date and cumulative production as of that date.Proved oil and gas reserves — Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of available geoscienceand engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirsand under existing economic conditions, operating methods, and government regulation — before the time at which contracts providing the right tooperate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used forthe estimation.The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within areasonable time.The area of the reservoir considered as proved includes all of the following:a. The area identified by drilling and limited fluid contacts, if any,b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or gas on the basis of available geoscience and engineering data.In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetrationunless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oilreserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technologyestablish the higher contact with reasonable certainty.Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when both of the following occur:a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operationof an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty ofthe engineering analysis on which the project or program was based.b. The project has been approved for development by all necessary parties and entities, including governmental entities.Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the averageprice during the 12-month period before the ending date of the period covered by the report, determined as an un-weighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon futureconditions.Proved developed oil and gas reserves — Proved oil and gas reserves that can be expected to be recovered:a. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minorcompared with the cost of a new well.b. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means notinvolving a well.Proved undeveloped oil and gas reserves — Proved oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or fromexisting wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsettingdevelopment spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishesreasonable certainty of economic producibility at greater distances.Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduledto be drilled within five years, unless the specific circumstances justify a longer time.Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogousreservoir, or by other evidence using reliable technology establishing reasonable certainty.102Table of Contents Reasonable certainty — If deterministic methods are used, a high degree of confidence that the quantities will be recovered. If probabilistic methodsare used, at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if thequantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, andgeochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely toincrease or remain constant than to decrease.Reliable technology — A grouping of one or more technologies (including computational methods) that has been field tested and demonstrated toprovide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.Reserves — Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there willexist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and allpermits and financing required to implement the project.Resources — Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to berecoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.Terms used to describe the legal ownership of the Company’s oil and natural gas properties •Revenue interest — The amount of the interest owned in the proceeds derived from a producing well less all royalty interests. •Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gasproduction or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and producesuch oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting hispercentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with thedevelopment and operation of a property.Terms used to describe seismic operations •Seismic data — Oil and natural gas companies use seismic data as their principal source of information to locate oil and natural gas deposits,both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy sourceis used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they aredetected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image ofunderground formations. •2-D seismic data — 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-Dseismic data produces an image of a single vertical plane of sub-surface data. •3-D seismic data — 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D surveyproduces a three-dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of informationthat can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliableindicator of potential oil and natural gas reservoirs in the area evaluated.Other Terms •All-in costs — For any period, means the sum of lease operating expenses, liquids gathering system operating lease expense, severance taxes,gathering costs, transportation charges, depletion, depreciation and amortization, interest expense and general and administrative expensesdivided by production on an Mcfe basis during the period. •Cash costs — For any period, means the sum of lease operating expenses, liquids gathering system operating lease expense, severance taxes,gathering costs, transportation charges, interest expense and general and administrative expenses divided by production on an Mcfe basis duringthe period. •Cash operating costs — For any period, means the sum of lease operating expenses, liquids gathering system operating lease expense, severancetaxes, gathering costs, transportation charges and general and administrative expenses divided by production on an Mcfe basis during the period. •Reserve replacement ratio — The sum of the estimated net proved reserves added through extensions, discoveries, revisions and additions(including purchases of reserves) for a specified period of time divided by production for that same period of time. •Finding and development costs — The sum of property acquisition costs, exploration costs and development costs for a specified period of time,divided by the total of proved reserve extensions, discoveries, revisions and additions (including purchases) for that same period of time. 103Exhibit 4.7THIRD SUPPLEMENTAL INDENTUREThis Third Supplemental Indenture, dated as of February 4, 2019 (this “Supplemental Indenture”), is among UltraResources, Inc., a Delaware corporation (the “Issuer”), Ultra Petroleum Corp., a Yukon, Canada corporation (the “Parent Guarantor”),the Subsidiary Guarantors party hereto (together with the Parent Guarantor, the “Guarantors”), and Wilmington Trust, NationalAssociation, as trustee (in such capacity together with its successors in such capacity, the “Trustee”) under the Indenture referred tobelow.W I T N E S S E T H:WHEREAS, the Issuer, the Guarantors, the Trustee and Wilmington Trust, National Association, as collateral agent, haveheretofore executed and delivered an Indenture, dated as of December 21, 2018 (as amended, supplemented, waived or otherwisemodified, the “Indenture”), providing for the issuance of an aggregate principal amount of $545,000,000 of 9.00% Cash / 2.00% PIKSenior Secured Second Lien Notes due 2024 of the Issuer;WHEREAS, Section 2.1(b) of the Indenture provides that, with respect to any Additional Notes issued after the Issue Date,the Issuer is required to set forth in a supplemental indenture certain information relating to the issuance of such Additional Notes; andWHEREAS, pursuant to Section 9.1(10) of the Indenture, the Issuer, the Guarantors and the Trustee are authorized toexecute and deliver this Supplemental Indenture to amend or supplement the Indenture, without the consent of any Noteholder.NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of whichis hereby acknowledged, the Issuer, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit ofthe Holders as follows:ARTICLE IDefinitionsSECTION 1.1. Defined Terms. As used in this Supplemental Indenture, terms defined in the Indenture or in thepreamble or recital hereto are used herein as therein defined. The words “herein,” “hereof” and “hereby” and other words of similarimport used in this Supplemental Indenture refer to this Supplemental Indenture as a whole and not to any particular section hereof.ARTICLE IIAdditional NotesSECTION 2.1. Additional Notes. On or about the date hereof, the Issuer intends to issue Additional Notes in anaggregate principal amount of $1,200,000 in exchange for $2,000,000 aggregate principal amount of the Issuer’s issued andoutstanding 2022 Notes, which shall be the issue price. Such Additional Notes shall in be in the form annexed hereto as Exhibit A,which shall contain such other terms as may be required pursuant to the Indenture.1 ARTICLE IIIMiscellaneousSECTION 3.1. Reserved.SECTION 3.2. Parties. Nothing expressed or mentioned herein is intended or shall be construed to give anyPerson, firm or corporation, other than the Holders and the Trustee, any legal or equitable right, remedy or claim under or in respect ofthis Supplemental Indenture or the Indenture or any provision herein or therein contained.SECTION 3.3. Governing Law. This Supplemental Indenture shall be governed by, and construed inaccordance with, the laws of the State of New York.SECTION 3.4. Severability Clause. In case any provision in this Supplemental Indenture shall be invalid, illegalor unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impairedthereby and such provision shall be ineffective only to the extent of such invalidity, illegality or unenforceability.SECTION 3.5. Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expresslyamended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remainin full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notesheretofore or hereafter authenticated and delivered shall be bound hereby. The Trustee makes no representation or warranty as to thevalidity or sufficiency of this Supplemental Indenture or with respect to the recitals contained herein, all of which recitals are madesolely by the other parties hereto.SECTION 3.6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect ofthe validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals aremade solely by the Issuer.SECTION 3.7. Counterparts. The parties hereto may sign one or more copies of this Supplemental Indenture incounterparts, all of which together shall constitute one and the same agreement. The exchange of copies of this SupplementalIndenture and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this instrument asto the parties hereto and may be used in lieu of the original instrument for all purposes. Signatures of the parties hereto transmitted byfacsimile or PDF shall be deemed to be their original signatures for all purposesSECTION 3.8. Headings. The headings of the Articles and the Sections in this Supplemental Indenture are forconvenience of reference only and shall not be deemed to alter or affect the meaning or interpretation of any provisions hereof. 2 IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date firstwritten above. Issuer: ULTRA RESOURCES, INC. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefFinancial Officer Parent Guarantor: ULTRA PETROLEUM CORP. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Chief Financial Officer Subsidiary Guarantors: UP ENERGY CORPORATION By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer KEYSTONE GAS GATHERING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer [Signature Page to Third Supplemental Indenture] ULTRA WYOMING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer UPL PINEDALE, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer UPL THREE RIVERS HOLDINGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer ULTRA WYOMING LGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and ChiefExecutive Officer WILMINGTON TRUST, NATIONAL ASSOCIATION, asTrustee By: /s/ Shawn Goffinet Name: Shawn Goffinet Title: Assistant Vice President [Signature Page to Third Supplemental Indenture] Exhibit AForm of Note Exhibit 4.8FOURTH SUPPLEMENTAL INDENTUREThis Fourth Supplemental Indenture, dated as of February 13, 2019 (this “Supplemental Indenture”), is among UltraResources, Inc., a Delaware corporation (the “Issuer”), Ultra Petroleum Corp., a Yukon, Canada corporation (the “Parent Guarantor”),the Subsidiary Guarantors party hereto (together with the Parent Guarantor, the “Guarantors”), and Wilmington Trust, NationalAssociation, as trustee (in such capacity together with its successors in such capacity, the “Trustee”) under the Indenture referred tobelow.W I T N E S S E T H:WHEREAS, the Issuer, the Guarantors, the Trustee and Wilmington Trust, National Association, as collateral agent, haveheretofore executed and delivered an Indenture, dated as of December 21, 2018 (as amended, supplemented, waived or otherwisemodified, the “Indenture”), providing for the issuance of an aggregate principal amount of $545,000,000 of 9.00% Cash / 2.00% PIKSenior Secured Second Lien Notes due 2024 of the Issuer;WHEREAS, Section 2.1(b) of the Indenture provides that, with respect to any Additional Notes issued after the Issue Date,the Issuer is required to set forth in a supplemental indenture certain information relating to the issuance of such Additional Notes; andWHEREAS, pursuant to Section 9.1(10) of the Indenture, the Issuer, the Guarantors and the Trustee are authorized toexecute and deliver this Supplemental Indenture to amend or supplement the Indenture, without the consent of any Noteholder.NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of whichis hereby acknowledged, the Issuer, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit ofthe Holders as follows:ARTICLE IDefinitionsSECTION 1.1. Defined Terms. As used in this Supplemental Indenture, terms defined in the Indenture or in thepreamble or recital hereto are used herein as therein defined. The words “herein,” “hereof” and “hereby” and other words of similarimport used in this Supplemental Indenture refer to this Supplemental Indenture as a whole and not to any particular section hereof.ARTICLE IIAdditional NotesSECTION 2.1. Additional Notes. On or about the date hereof, the Issuer intends to issue Additional Notes in anaggregate principal amount of $10,116,750 in exchange for $16,450,000 aggregate principal amount of the Issuer’s issued andoutstanding 2022 Notes, which shall be the issue price. Such Additional Notes shall in be in the form annexed hereto as Exhibit A,which shall contain such other terms as may be required pursuant to the Indenture.1 ARTICLE IIIMiscellaneousSECTION 3.1. Reserved. SECTION 3.2. Parties. Nothing expressed or mentioned herein is intended or shall be construed to give anyPerson, firm or corporation, other than the Holders and the Trustee, any legal or equitable right, remedy or claim under or in respect ofthis Supplemental Indenture or the Indenture or any provision herein or therein contained.SECTION 3.3. Governing Law. This Supplemental Indenture shall be governed by, and construed inaccordance with, the laws of the State of New York.SECTION 3.4. Severability Clause. In case any provision in this Supplemental Indenture shall be invalid, illegalor unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impairedthereby and such provision shall be ineffective only to the extent of such invalidity, illegality or unenforceability.SECTION 3.5. Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expresslyamended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remainin full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notesheretofore or hereafter authenticated and delivered shall be bound hereby. The Trustee makes no representation or warranty as to thevalidity or sufficiency of this Supplemental Indenture or with respect to the recitals contained herein, all of which recitals are madesolely by the other parties hereto.SECTION 3.6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect ofthe validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals aremade solely by the Issuer.SECTION 3.7. Counterparts. The parties hereto may sign one or more copies of this Supplemental Indenture incounterparts, all of which together shall constitute one and the same agreement. The exchange of copies of this SupplementalIndenture and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this instrument asto the parties hereto and may be used in lieu of the original instrument for all purposes. Signatures of the parties hereto transmitted byfacsimile or PDF shall be deemed to be their original signatures for all purposesSECTION 3.8. Headings. The headings of the Articles and the Sections in this Supplemental Indenture are forconvenience of reference only and shall not be deemed to alter or affect the meaning or interpretation of any provisions hereof. 2 IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the datefirst written above. Issuer: ULTRA RESOURCES, INC. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Financial Officer Parent Guarantor: ULTRA PETROLEUM CORP. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Chief Financial Officer Subsidiary Guarantors: UP ENERGY CORPORATION By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer KEYSTONE GAS GATHERING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer [Signature Page to Fourth Supplemental Indenture] ULTRA WYOMING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer UPL PINEDALE, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer UPL THREE RIVERS HOLDINGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer ULTRA WYOMING LGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer WILMINGTON TRUST, NATIONAL ASSOCIATION, asTrustee By: /s/ Shawn Goffinet Name: Shawn Goffinet Title: Assistant Vice President [Signature Page to Fourth Supplemental Indenture] Exhibit AForm of Note Exhibit 4.9FIFTH SUPPLEMENTAL INDENTUREThis Fifth Supplemental Indenture, dated as of February 15, 2019 (this "Supplemental Indenture"), is among UltraResources, Inc., a Delaware corporation (the "Issuer"), Ultra Petroleum Corp., a Yukon, Canada corporation (the "Parent Guarantor"),the Subsidiary Guarantors party hereto (together with the Parent Guarantor, the "Guarantors"), and Wilmington Trust, NationalAssociation, as trustee (in such capacity together with its successors in such capacity, the "Trustee") under the Indenture referred tobelow.W I T N E S S E T H:WHEREAS, the Issuer, the Guarantors, the Trustee and Wilmington Trust, National Association, as collateral agent, haveheretofore executed and delivered an Indenture, dated as of December 21, 2018 (as amended, supplemented, waived or otherwisemodified, the "Indenture"), providing for the issuance of an aggregate principal amount of $545,000,000 of 9.00% Cash / 2.00% PIKSenior Secured Second Lien Notes due 2024 of the Issuer;WHEREAS, Section 2.1(b) of the Indenture provides that, with respect to any Additional Notes issued after the Issue Date,the Issuer is required to set forth in a supplemental indenture certain information relating to the issuance of such Additional Notes; andWHEREAS, pursuant to Section 9.1(10) of the Indenture, the Issuer, the Guarantors and the Trustee are authorized toexecute and deliver this Supplemental Indenture to amend or supplement the Indenture, without the consent of any Noteholder.NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of whichis hereby acknowledged, the Issuer, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit ofthe Holders as follows:ARTICLE IDefinitionsSECTION 1.1. Defined Terms. As used in this Supplemental Indenture, terms defined in the Indenture or in thepreamble or recital hereto are used herein as therein defined. The words "herein," "hereof" and "hereby" and other words of similarimport used in this Supplemental Indenture refer to this Supplemental Indenture as a whole and not to any particular section hereof.ARTICLE IIAdditional NotesSECTION 2.1. Additional Notes. On or about the date hereof, the Issuer intends to issue Additional Notes in anaggregate principal amount of $1,230,000 in exchange for $2,000,000 aggregate principal amount of the Issuer's issued andoutstanding 2022 Notes, which shall be the issue price. Such Additional Notes shall in be in the form annexed hereto as Exhibit A,which shall contain such other terms as may be required pursuant to the Indenture.1ARTICLE IIIMiscellaneousSECTION 3.1. Reserved. SECTION 3.2. Parties. Nothing expressed or mentioned herein is intended or shall be construed to give anyPerson, firm or corporation, other than the Holders and the Trustee, any legal or equitable right, remedy or claim under or in respect ofthis Supplemental Indenture or the Indenture or any provision herein or therein contained.SECTION 3.3. Governing Law. This Supplemental Indenture shall be governed by, and construed inaccordance with, the laws of the State of New York.SECTION 3.4. Severability Clause. In case any provision in this Supplemental Indenture shall be invalid, illegalor unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impairedthereby and such provision shall be ineffective only to the extent of such invalidity, illegality or unenforceability.SECTION 3.5. Ratification of Indenture; Supplemental Indentures Part of Indenture. Except as expresslyamended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remainin full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notesheretofore or hereafter authenticated and delivered shall be bound hereby. The Trustee makes no representation or warranty as to thevalidity or sufficiency of this Supplemental Indenture or with respect to the recitals contained herein, all of which recitals are madesolely by the other parties hereto.SECTION 3.6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect ofthe validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals aremade solely by the Issuer.SECTION 3.7. Counterparts. The parties hereto may sign one or more copies of this Supplemental Indenture incounterparts, all of which together shall constitute one and the same agreement. The exchange of copies of this SupplementalIndenture and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this instrument asto the parties hereto and may be used in lieu of the original instrument for all purposes. Signatures of the parties hereto transmitted byfacsimile or PDF shall be deemed to be their original signatures for all purposesSECTION 3.8. Headings. The headings of the Articles and the Sections in this Supplemental Indenture are forconvenience of reference only and shall not be deemed to alter or affect the meaning or interpretation of any provisions hereof. 2 IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the datefirst written above. Issuer: ULTRA RESOURCES, INC. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Financial Officer Parent Guarantor: ULTRA PETROLEUM CORP. By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Chief Financial Officer Subsidiary Guarantors: UP ENERGY CORPORATION By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer KEYSTONE GAS GATHERING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer [Signature Page to Fifth Supplemental Indenture] ULTRA WYOMING, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer UPL PINEDALE, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer UPL THREE RIVERS HOLDINGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer ULTRA WYOMING LGS, LLC By: /s/ David W. Honeyfield Name: David W. Honeyfield Title: Senior Vice President and Chief Executive Officer WILMINGTON TRUST, NATIONAL ASSOCIATION, asTrustee By: /s/ Shawn Goffinet Name: Shawn Goffinet Title: Assistant Vice President [Signature Page to Fifth Supplemental Indenture] Exhibit AForm of Note Exhibit 10.37EMPLOYMENT AGREEMENTTHIS EMPLOYMENT AGREEMENT (this “Agreement”) is entered into by and between ULTRA PETROLEUM CORP., aYukon corporation (“Ultra”), and DAVID W. HONEYFIELD (“Executive”).WHEREAS, Ultra desires to employ Executive and to embody herein the terms of such employment, and considers it to be in its bestinterests and in the best interests of its stockholders to employ Executive during the Employment Period (as defined in Section 1below); andWHEREAS, Executive is willing to accept such employment with Ultra upon the terms and conditions of this Agreement;NOW, THEREFORE, in consideration of the mutual covenants contained herein and other good and valuable consideration, thereceipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:1.Date of Agreement; Employment Period. This Agreement is entered into November 5, 2018. The employment periodhereunder shall become effective beginning at the start of business on November 9, 2018 (the “Effective Date”) and shallcontinue until the termination of Executive’s employment hereunder (the “Employment Period”).2.Positions and Duties. While this Agreement is in effect: (a)Executive shall serve as the Chief Financial Officer of Ultra and shall have the normal authority, responsibilitiesand duties of an executive in such position and such other reasonably related duties and responsibilities, in eachcase, that are assigned by the Company. (b)Executive shall report to the Chief Executive Officer (interim) of Ultra. (c)Executive agrees to devote his full business time and attention to the business and affairs of Ultra; provided,however, that Executive may also manage his personal, financial, and legal affairs and engage in other passiveprofessional, charitable or community activities so long as such other activities do not conflict with Ultra’sinterests, interfere with Executive’s duties and responsibilities to Ultra or the Subsidiaries, or violate any ofExecutive’s duties and obligations hereunder. Further, Executive may accept an appointment to the board ofdirectors of a for-profit business, provided and only to the extent that (i) Executive has approval from the board ofdirectors of Ultra prior to accepting such an appointment and (ii) Executive is and will remain in compliance withall restrictive covenants in this Agreement while Executive holds any such position. (d)Executive agrees to comply with and, where applicable, enforce the policies of Ultra and of the Subsidiaries,including, without limitation, such policies with respect to legal compliance, conflicts of interest, confidentiality,professional conduct and business ethics as are from time to time in effect. Executive shall cooperate with any investigation orinquiry authorized by the Board or conducted by a governmental authority related to the business of Ultra or anyof the Subsidiaries or Executive’s performance under this Agreement.3.Compensation and Reimbursements. While this Agreement is in effect: (a)Base Salary. (i)Beginning on the Effective Date and continuing during the Employment Period, Ultra agrees to payExecutive a base salary (the “Base Salary”) at the annual rate of $500,000, payable in regularinstallments in accordance with Ultra’s usual payroll practices. (ii)Executive’s Base Salary will be reviewed at least annually by the Compensation Committee of theBoard of Directors of Ultra Petroleum Corp. (the “Compensation Committee”) and may be adjusted inits sole discretion. (b)Sign-On Bonus. (i)Executive shall be entitled to receive payment of a sign-on bonus of $100,000 (the “Sign-On Bonus”),which shall be paid as follows: $50,000 shall be paid no later than January 31, 2019, and $50,000 shallbe paid as soon as practicable following the first anniversary of the Effective Date, but in all events nolater than 30 days after the first anniversary of the Effective Date, provided Executive remainsemployed on each applicable payment date. If Executive is terminated by Ultra for Cause or Executiveterminates his employment other than with Good Reason, in each case before the first anniversary of theEffective Date, Executive must, within thirty (30) days of the applicable termination date, repay, toUltra, the full gross amount of Sign-On Bonus previously paid to Executive. If Executive’s employmentis terminated before the first anniversary of the Effective Date due to Disability or as a result ofExecutive’s death, Executive (or Executive’s estate) must repay $25,000 of the Sign-On Bonus withinninety (90) days of such termination. (c)Incentive Compensation (Cash). (i)Executive shall be eligible to receive cash incentive compensation (any such compensation, a “CashIncentive”) pursuant to the short-term incentive program for Ultra established by the CompensationCommittee for senior executives of Ultra (such program, an “AIP”). Executive’s target Cash Incentiveamount shall be equal to ninety percent (90%) of Executive’s Base Salary (the “Target AIP Amount”). (ii)Executive’s Target AIP Amount will be reviewed at least annually by the Compensation Committeeand may be adjusted in its sole discretion.Page 2 of 14  (iii)During the first quarter after the end of the performance period applicable to an AIP, the CompensationCommittee will evaluate Ultra’s performance compared to the performance targets and goals in the then-applicable AIP and determine the aggregate amount that has been earned by participants under the AIP.Thereafter, the Compensation Committee shall determine, taking into account Executive’s performance,the amount of any AIP payout to Executive, which may be between 0% and 200% of Executive’sTarget AIP Amount, and cause Ultra Resources to pay the applicable Cash Incentive, if any, toExecutive. (iv)Executive must be employed by Ultra on the date a Cash Incentive is to be paid in order to receive thepayment. (d)Incentive Compensation (Equity). Executive will be eligible to receive an award of restricted stock units under theStock Incentive Plan (defined below), subject to approval of the Compensation Committee and the terms andconditions of the Stock Incentive Plan and the award agreement attached hereto as Schedule 2. (e)Employee Benefits and Insurance. (i)Executive is entitled to participate in and receive full rights and benefits available under all of thefollowing, to the extent existing on the Effective Date or enacted or implemented after the EffectiveDate: life insurance; disability insurance; directors and officers liability insurance; health and accidentplans, including medical, dental and vision plans; 401(k) plan; and any other welfare, fringe oremployee benefits plans or programs implemented by Ultra or any of the Subsidiaries. (ii)Ultra is not required to have or maintain any employee benefit programs or insurance, and Ultra maymodify any employee benefit programs or insurance applicable to Executive. (f)Vacation. Executive shall be entitled to paid vacation equal to 5 weeks, such vacation to be taken in accordancewith Ultra’s vacation policy; provided, however, Executive’s vacations shall be taken at times that are consistentwith Ultra’s reasonable business needs; and, provided, further, that Executive agrees not to take vacation for morethan ten (10) consecutive business days at any given time without prior consent from Executive’s Supervisor. (g)Business Expenses; Reimbursement. Ultra shall reimburse Executive for all reasonable business expenses incurredduring the performance of Executive’s duties hereunder to the extent consistent with its written policies in effectfrom time to time, including with respect to the reporting and documentation of such expenses.4.Termination of Employment. While this Agreement is in effect:Page 3 of 14  (a)Ultra may terminate Executive’s employment at any time and for whatever reason, and Executive may resignExecutive’s employment at any time and for whatever reason upon no less than 30 days’ notice. The remainingclauses of this Section 4(a) set forth and shall determine the respective rights and obligations of Ultra andExecutive arising upon and resulting from any such termination or resignation. The definitions of certaincapitalized terms used in this Section 4 are set forth in Section 4(b). (i)Termination by Ultra: For “Cause.” (A)If Cause exists, then Ultra may terminate Executive’s employment for Cause; provided that ifUltra elects to terminate Executive’s employment for Cause, then Ultra shall provide writtennotice to Executive specifying that Ultra is terminating Executive’s employment for Cause,providing a reasonable description of the basis therefor, and specifying the effective date ofsuch termination, which may be immediate. (B)If Executive’s employment is terminated for Cause, then Ultra shall pay Executive anyAccrued Obligations as of the Termination Date but shall have no other obligation to pay orprovide Executive any severance or benefits, and Executive shall have no right to any otherpayments, severance or other benefits. (C)In addition, if Executive’s employment is terminated for Cause, Executive will forfeit alloutstanding Equity Incentives and any other outstanding equity awards of Ultra, whethervested or unvested, and will remain bound by any Ultra’s clawback policy in effect as of thedate of termination. (ii)Termination by Ultra: Without “Cause.” (A)Ultra may terminate Executive’s employment without Cause; provided that if Ultra elects toterminate Executive’s employment without Cause, then Ultra shall provide written notice toExecutive specifying that Ultra is terminating Executive’s employment without Cause andspecifying the effective date of such termination, which may be immediate. (B)If Executive’s employment is terminated without Cause, then Ultra shall pay or provide toExecutive: (i) any Accrued Obligations as of the Termination Date, (ii) the Pro-Rata CashIncentive, (iii) the Severance Payment; and (iv) the Severance Benefits. Ultra will have noother obligation to pay Executive any other severance or termination benefits. (iii)Resignation by Executive: Without “Good Reason”Page 4 of 14  (A)Executive may resign Executive’s employment for any reason; provided that if Executiveelects to resign, then Executive shall provide written notice to Ultra specifying that Executiveis resigning and specifying the effective date thereof, which shall be no less than 30 days afterdelivery of such notice . (B)If Executive resigns Executive’s employment, then Ultra shall pay Executive any AccruedObligations as of the Termination Date but shall have no other obligation to pay or provideExecutive any severance or benefits, and Executive shall have no right to any otherpayments, severance or other benefits. (iv)Resignation by Executive: With “Good Reason” (A)Executive may resign Executive’s employment with Ultra with Good Reason; provided thatif Executive elects to resign Executive’s employment with Good Reason, then Executiveshall provide written notice to Ultra specifying that Executive is resigning with Good Reason. (B)If Executive’s resigns Executive’s employment with Good Reason, then Ultra shall pay orprovide to Executive: (i) any Accrued Obligations as of the Termination Date, (ii) the Pro-Rata Cash Incentive, (iii) the Severance Payment; and (iv) the Severance Benefits. Ultra willhave no other obligation to pay Executive any other severance or termination benefits. (v)Executive’s “Disability.” (A)Ultra may terminate Executive’s employment and officer and director positions upon adetermination that Executive has suffered a Disability; provided, however, that if Ultra electsto terminate Executive’s employment because Executive has suffered a Disability, Ultra mustprovide written notice to Executive specifying that Ultra is terminating Executive’semployment as a result of a Disability and specifying the effective date thereof, which may beimmediate. (B)Upon a termination of Executive’s employment due to Disability, Executive shall be entitledto receive, and Ultra shall pay to Executive, as promptly as possible, any AccruedObligations as of the Termination Date and the Pro-Rata Cash Incentive. (vi)Executive’s Death. (A)Executive’s employment and officer and director positions shall terminate upon Executive’sdeath. In the event of Executive’s death,Page 5 of 14  the Termination Date shall be deemed to be the date of Executive’s death. (B)Upon Executive’s death, Executive’s estate shall be entitled to receive, and Ultra shall pay toExecutive’s estate, as promptly as possible, any Accrued Obligations as of the TerminationDate and the Pro-Rata Cash Incentive. (vii)Timing of Payments and Benefits. The payments and benefits contemplated in this Section 4(a) shall beprovided to Executive at the times and in the manner specified below: (A)The Accrued Obligations shall be paid pursuant to Ultra’s standard payroll and otherpractices and at the time and in the manner required by applicable law but in no event laterthan thirty days after the Termination Date; provided, however, the Accrued Obligationsdescribed in clause (C) of the definition of Accrued Obligations shall be paid or provided atthe time and pursuant to the terms of the applicable plans or programs at the TerminationDate. (B)The Pro-Rata Cash Incentive shall be paid as soon as is administratively feasible after the endof the performance period for the applicable Cash Incentive, but in no event later than March15 of the calendar year following the calendar year to which such Cash Incentive relates. (C)The Severance Benefits shall be paid or provided at the time and pursuant to the terms of theapplicable plans or programs at the Termination Date. (D)The Severance Payment shall be paid in cash and in a lump sum within thirty (30) daysfollowing Executive’s timely execution and non-revocation of the release of claims in favorof Ultra as described in Section 4(e). (b)As used herein, the following terms have the following meanings: (i)“Accrued Obligations” means, collectively: (A) any accrued and unpaid Base Salary throughTermination Date; (B) any unreimbursed Business Expenses incurred and paid by Executive up to andincluding the Termination Date; and (C) any other vested compensation or benefits payable toExecutive based on the express terms of Ultra’s compensation or benefit plans or programs andExecutive’s participation therein. (ii)“Cause” means the occurrence of one or more of the following as determined by the Board:Page 6 of 14  (A)Executive’s willful misconduct or gross negligence in the performance of Executive’s dutiesto Ultra; or (B) Executive’s repeated failure to perform Executive’s duties to Ultra or to follow the lawfuldirectives of the Board or other applicable supervisor (other than as a result of death orphysical or mental incapacity); or (C)Executive’s commission of, indictment for, conviction of, or pleading of guilty or nolocontendere to, a felony or any crime involving moral turpitude; or (D)Executive’s performance of any act of theft, embezzlement, fraud, malfeasance, dishonesty ormisappropriation of Ultra’s or any of its customer’s, supplier’s or distributor’s property; or (E)Executive’s use of illegal drugs or Executive’s abuse of alcohol that materially impairsExecutive’s ability to perform Executive’s duties to Ultra; or (F)Executive’s material breach of any fiduciary duty owed to Ultra (including, withoutlimitation, the duty of care and the duty of loyalty); or (G)Executive’s material breach of any agreement with Ultra, or a material violation of Ultra’scode of conduct or other written policy. (H)Notwithstanding anything to the contrary contained herein, Executive’s resignation after anevent that would be grounds for a termination for Cause shall be treated as a termination forCause. (iii)“Disability” means Executive’s inability to perform the essential duties, responsibilities and functions ofExecutive’s positions as a result of a physical illness or impairment, a mental illness or impairment, oranother physical, mental or legal incapacity, during a period of twelve consecutive weeks or acumulative period of ninety days during any twelve-month period. (iv)“Good Reason” means the occurrence of one or more of the following: (A)Any material reduction of Executive’s then-existing annual Base Salary or Target AIPAmount; (B)Any material diminution of Executive’s duties, responsibilities or authority set forth inSection 2, unless Executive consents in writing to any such diminution; orPage 7 of 14  (C)A relocation of Executive’s principal workplace to a work site that would increase theExecutive’s one-way commute distance by more than fifty (50) miles from Executive’s thenexisting workplace, unless Executive consents in writing to such relocation. (v)“Pro-Rata Cash Incentive” means an amount equal to the product of: (x) the Cash Incentive whichExecutive would have earned pursuant to Section 3(c) hereof for the calendar year during which theTermination Date occurred, as determined based on Executive’s Target AIP Amount and Ultra’sperformance relative to the performance targets in goals specified in the applicable AIP; and (y) afraction, the numerator of which is the number of days between January 1 of the applicable calendaryear and the Termination Date, and the denominator of which is 365. (vi)“Severance Benefits” means the benefits described in Section 3(e)(i) hereof, which Ultra shall makeavailable to Executive, at Ultra’s cost and expense, for a period beginning on the Termination Date andcontinuing for 12 months or, if earlier occurring, such time as Executive obtains other employment thatprovides Executive with benefits at least as favorable to Executive as the benefits described in Section3(e)(i) hereof. (vii)“Severance Payment” means an amount, payable in U.S. dollars, equal to the sum of: (x) one hundredpercent (100%) of Executive’s Base Salary in effect on the Termination Date and (y) any CashIncentive earned, but not yet paid, for the year prior to the year of termination. (viii)“Stock Incentive Plan” means the Ultra Petroleum Corp. 2017 Amended and Restated Stock IncentivePlan, dated and amended and restated effective as of June 8, 2018. (ix)“Termination Date” means the effective date of a termination or resignation, as applicable, as specifiedor provided for under Section 4(a) above. (c)Resignations. Upon any termination of Executive’s employment hereunder for any reason: (i)Executive agrees to resign from all officer, director, and other positions Executive may then hold withUltra and each of the Subsidiaries and any other affiliates of Ultra or any Subsidiary existing at suchtime; and (ii)Executive agrees to execute and deliver any reasonable documentation requested by Ultra or anySubsidiary reflecting such resignations. (iii)Notwithstanding the foregoing and for the avoidance of doubt, any termination of Executive’semployment shall constitute and be deemed to signify an automatic resignation of Executive, as of theTermination Date, from all positions he then holds as an employee, officer, director, manager or otherservice provider to Ultra and each Subsidiary.Page 8 of 14  (d)Exclusive Compensation and Benefits; Time Periods. The compensation and benefits described in this Section 4,along with the associated terms for payment, constitute all of Ultra’s obligations to Executive and all of Executiverights with respect to Ultra in connection with any termination of Executive’s employment; provided, however,that nothing herein, is intended to limit any rights Executive may have to continue or convert insurance coverageunder certain employee benefit plans in accordance with the terms of those plans and applicable law and furtherprovided that nothing herein is intended to limit any rights Executive has pursuant to the Stock Incentive Plan.Time periods applicable to the determination of a Severance Payment amount shall include periods prior to theEffective Date, as applicable. (e)Conditions, Release of Claims. Any and all amounts payable and benefits or additional rights provided pursuant tothis Agreement beyond the Accrued Obligations shall only be payable if Executive delivers to Ultra and does notrevoke a general release of claims in favor of Ultra in Ultra’s then customary form. Such release shall be executedand delivered (and no longer subject to revocation, if applicable) within sixty (60) days following termination. Inno event shall Executive be obligated to seek other employment or take any other action by way of mitigation ofthe amounts payable to Executive under any of the provisions of this Agreement, nor shall the amount of anypayment hereunder be reduced by any compensation earned by Executive as a result of employment by asubsequent employer, Subject to the provisions of Schedule 1 hereof and the limitations of applicable wage laws,Ultra’s obligation to pay Executive amounts hereunder shall be subject to set-off, counterclaim or recoupment ofamounts owed by Executive to Ultra or any of its affiliates.5.Tax Matters. The provisions of Schedule 1 attached hereto setting out the parties intent with respect to certain tax matters andaddressing the applicability of certain provisions of the Internal Revenue Code of 1986 and the regulations and guidancepromulgated thereunder apply to the matters addressed herein as though set forth in full herein and are deemed incorporatedinto this Agreement for all purposes.6.Confidential Information. (a)Executive agrees to maintain all Confidential Information in confidence in a fiduciary capacity for the exclusivebenefit of Ultra and the Subsidiaries and further agrees not to disclose, directly or indirectly, any of theConfidential Information except as and to the extent required for the performance of Executive’s duties,responsibilities or functions under this Agreement. (b)Executive acknowledges that money damages would not be a sufficient remedy for any breach of this Section 6by Executive, and Executive agrees that Ultra or any affected Subsidiary may enforce the provisions of thisSection 6 by obtaining an order for specific performance and/or injunctive relief as remedies for any such breachor threatened breach. Such remedies are not the exclusive remedies for aPage 9 of 14  breach of this Section 6, but shall be in addition to all remedies available at law or in equity to Ultra. (c)As used herein, “Confidential Information” means all information and material which is confidential or proprietaryto Ultra or any of the Subsidiaries, including any non-public operational, financial or other business informationand any trade secrets, whether or not any such information is reduced to writing or other tangible form, whether ornot any such information is marked as “confidential” or “proprietary,” and whether or not any such information isprepared by or for Ultra or any of the Subsidiaries. (d)At the termination of Executive’s employment hereunder, Executive shall deliver to Ultra all ConfidentialInformation then in Executive’s possession or control and shall not retain or use any copies or summaries thereof. (e)Notwithstanding anything to the contrary in this Agreement, Ultra may transfer or assign the benefits of thisprovision to a party that acquires all or substantially all of Ultra’s assets or all or substantially all of the oil and gasassets owned by the Subsidiaries, taken as a whole.7.Inventions. (a)Executive shall hold any Inventions (as defined below) in trust for the benefit of Ultra, Executive shall discloseany Inventions promptly and fully to Ultra in writing, and Executive hereby assigns any Inventions, and binds hisheirs, executors, and administrators to assign any Inventions, to Ultra or its designee. (b)Any and all Inventions shall be and are Ultra’s sole and exclusive property, whether patentable, copyrightable, orneither, and Executive shall assist and fully cooperate in every way, at Ultra’s expense, in securing, maintaining,and enforcing, for the benefit of Ultra or its designee, patents, copyrights or other types of proprietary orintellectual property protection for such Developments in any and all countries. Further, all works of authorshipcreated by Executive, solely or jointly with others, shall be considered works made for hire under the CopyrightAct of 1976, as amended, and shall be owned entirely by Ultra. (c)As used herein, “Inventions” means any and all inventions, discoveries, ideas, concepts, improvements, works ofauthorship (including copyrightable works), and other developments that are conceived, made, discovered ordeveloped by Executive, solely or jointly with others, during the term of his employment by Ultra, whether duringor outside of usual working hours and whether on Ultra’s premises or not, to the extent any of the foregoing relatein any manner to the past, present or anticipated business of Ultra or any of the Subsidiaries. (d)18 U.S.C. § 1833(b) provides: “An individual shall not be held criminally or civilly liable under any federal orstate trade secret law for the disclosure of a trade secret that (A) is made (x) in confidence to a federal, state, orlocal government official, either directly or indirectly, or to an attorney; and (y) solely for the purpose ofPage 10 of 14  reporting or investigating a suspected violation of law; or (B) is made in a complaint or other document filed in alawsuit or other proceeding, if such filing is made under seal.” Nothing in this Agreement is intended to conflictwith 18 U.S.C. § 1833(b) or create liability for disclosures of trade secrets that are expressly allowed by 18 U.S.C.§ 1833(b). Accordingly, the parties to this Agreement have the right to disclose in confidence trade secrets tofederal, state, and local government officials, or to an attorney, for the sole purpose of reporting or investigating asuspected violation of law. The parties also have the right to disclose trade secrets in a document filed in a lawsuitor other proceeding, but only if the filing is made under seal and protected from public disclosure.8.Cooperation and Assistance. During a three-year period following a Termination Date, at Ultra’s request Executive willreasonably cooperate in connection with any litigation or other fact-finding or adjudicative proceedings involving Ultra orany Subsidiary, provided Executive is not required to travel beyond the city or town where Executive then lives or toprovide assistance that unreasonably interferes with Executive’s employment or other activities or endeavors and Executiveis not required to provide over 50 hours assistance during any 12-month period. Ultra will pay Executive a reasonable hourlyrate for Executive’s assistance, reimburse Executive for all reasonable out-of-pocket expenses incurred by Executive inconnection with rendering such assistance, and provide Executive counsel reasonably suitable to Executive to representExecutive in connection with providing such assistance if Executive reasonably requests.9.Protected Disclosures and Actions. Notwithstanding anything to the contrary contained herein, no provision of thisAgreement shall be interpreted so as to impede Executive (or any other individual) from reporting possible violations offederal law or regulation to any governmental agency or entity, including but not limited to the Department of Justice, theSecurities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures underthe whistleblower provisions of federal law or regulation. Executive does not need the prior authorization of Ultra to makeany such reports or disclosures and Executive shall not be required to notify Ultra that such reports or disclosures have beenmade.10.Non-Competition. Executive expressly covenants and agrees that, without the prior written consent of Ultra, during a one-year period beginning on the Termination Date (as determined pursuant to the terms hereof) and ending on the firstanniversary of such Termination Date, Executive shall not participate or engage in, directly or indirectly (as an owner,partner, employee, officer, director, independent contractor, consultant, advisor or in any other capacity calling for therendition of services, advice, or acts of management, operation or control) any business for a Competitor (as defined below)anywhere within Sublette County, Wyoming or twenty miles of any properties owned by the Company in the United Stateson the Termination Date. The term "Competitor" means any business, individual, partnership, firm, corporation or otherentity engaged in oil and gas exploration and production.11.Non-Solicitation. Executive expressly covenants and agrees that, without the prior written consent of Ultra, during a one-year period beginning on the Termination Date (asPage 11 of 14 determined pursuant to the terms hereof) and ending on the first anniversary of such Termination Date, Executive will notdirectly or indirectly: (i) solicit the employment or engagement as a consultant of any person who is or was an employee ofor a consultant to Ultra or any Subsidiary at any time during the last twelve months of Executive’s employment with Ultra;or (ii) hire or engage any such person.12.Non-Disparagement. Executive agrees not to make or publish any Disparaging Remarks (as defined below) to any otherperson about: (i) Ultra or any Subsidiary; (ii) any business conducted by Ultra or any Subsidiary; or (iii) any past or presentmember of Ultra’s management or board of directors in their capacity as such. As used herein, the term “DisparagingRemarks” means any statement, whether written or oral, that has the intention or tendency to degrade, diminish, or harm thereputation or standing of an individual or entity in the estimation of a community, including by deterring or having atendency to deter others from associating, employing, or otherwise dealing with them.13.Reasonableness of Covenants. In signing this Agreement, Executive gives Ultra assurance that Executive has carefully readand considered all of the terms and conditions of this Agreement, including the restraints imposed under Section 6 thoughSection 12. Executive agrees that these restraints are necessary for the reasonable and proper protection of Ultra and itsaffiliates and their Confidential Information and that each and every one of the restraints is reasonable in respect of subjectmatter, length of time and geographic area, and that these restraints, individually or in the aggregate, will not preventExecutive from obtaining other suitable employment during the period in which Executive is bound by the restraints.Executive acknowledges that each of these covenants has a unique, very substantial and immeasurable value to Ultra and itsaffiliates and that Executive has sufficient assets and skills to provide a livelihood while such covenants remain in force.Executive further covenants that Executive will not challenge the reasonableness or enforceability of any of the covenantsand that the Executive will reimburse Ultra and its affiliates for all costs (including reasonable attorneys’ fees) incurred inconnection with any action to enforce any of the provisions of Sections 6 through Section 12 if either Ultra and/or itsaffiliates prevails on any material issue involved in such dispute or if Executive challenges the reasonableness orenforceability of any of the provisions of Section 6 through Section 12. It is also agreed that each of Ultra’s affiliates willhave the right to enforce all of Executive’s obligations to that affiliate under this Agreement, including without limitationpursuant to Section 6 through Section 12. Upon Executive’s material breach of the provisions of Section 6 through Section12, Executive will be required to repay the Severance Payment to Ultra.14.Reformation. If it is determined by a court of competent jurisdiction in any state that any restriction in Section 6 throughSection 12 is excessive in duration or scope or is unreasonable or unenforceable under applicable law, it is the intention ofthe parties that such restriction may be modified or amended by the court to render it enforceable to the maximum extentpermitted by the laws of that state.15.Tolling. In the event of any violation of the provisions of Section 6 through Section 12, the Executive acknowledges andagrees that the post-termination restrictions contained in this Section 6 through Section 12 shall be extended by a period oftime equal to the period ofPage 12 of 14 such violation, it being the intention of the parties hereto that the running of the applicable post-termination restriction periodshall be tolled during any period of such violation.16.Survival of Provisions. The obligations contained in Section 6 through Section 12 hereof shall survive the termination orexpiration of the Employment Period and Executive’s employment with Ultra and shall be fully enforceable thereafter.17.General Provisions. (a)Amendments and Waiver; Prior Agreements. (i)The terms and provisions of this Agreement may not be modified or amended, nor may any of theprovisions hereof be waived, temporarily or permanently, unless such modification or amendment isagreed to in writing and signed by Executive, on the one hand, and by a duly authorized person onbehalf of Ultra, on the other hand. (ii)Any failure of any party hereto to enforce any of the provisions of this Agreement shall in no way beconstrued as a waiver of such provisions and shall not affect the right of such party thereafter to enforceeach and every provision of this Agreement in accordance with its terms, and, further, a waiver by aparty on one occasion shall not be deemed to be a waiver of the same or any other type of breach on afuture occasion. (iii)Except to the extent set forth in the plan or program documents related to the employee benefits plans orprograms of Ultra or any of the Subsidiaries, this Agreement supersedes and replaces any otheremployment agreement between Ultra and Executive. Any such other employment agreement shall nolonger be in force and effect. (b)Binding Agreement; Permitted Successors and Assigns. (i)This Agreement shall bind and inure to the benefit of and be enforceable by the parties hereto and theirrespective successors, permitted assigns, heirs and personal representatives and estates, as the case maybe, and this Agreement shall not confer any rights or remedies upon any other person or legal entity. (ii)Neither this Agreement nor any right or obligation hereunder of any party may be assigned or delegatedwithout the prior written consent of the other party; provided, Executive may direct distribution of anybenefits or compensation that, upon Executive’s death, accrue hereunder. (iii)Executive shall not have any right to pledge, hypothecate, anticipate, or in any way create a lien uponany payments or other benefits provided under this Agreement; and no benefits payable under thisAgreement shall be assignable in anticipation of payment either by voluntary or involuntaryPage 13 of 14  acts, or by operation of law, except by will or pursuant to the laws of descent and distribution. (c)Survival. The termination of Executive’s employment shall not impair the rights or obligations of any party thathave accrued prior to such termination or which by their nature or terms survive termination of the Term,including without limitation the parties’ respective obligations under Sections 4 through 12 hereof. (d)Validity. The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect thevalidity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. (e)Governing Law; Jurisdiction; Venue; Jury-Trial Waiver; Fees and Expenses. (i)This Agreement is governed by and shall be construed and enforced in accordance with Colorado law,excluding its choice-of-law principles, except where federal law may preempt the application of statelaw. (ii)The parties hereto: (A) submit and consent to the exclusive jurisdiction, including removal jurisdiction,of the state and federal courts located in Denver, CO for any action or proceeding relating to thisAgreement or Executive’s employment; (B) waive any objection to such venue; (C) agree that anyjudgment in any such action or proceeding may be enforced in other jurisdictions; and (D) irrevocablywaive the right to trial by jury and agree not to ask for a jury in any such proceeding. (f)No Obligation to Pay. With regard to any payment due to Executive under this Agreement, it shall not be a breachof any provision of this Agreement for Ultra to fail to make such payment to Executive if, by doing so, Ultrawould violate any applicable law.[Signature Page Follows] Page 14 of 14  IN WITNESS WHEREOF, the parties hereto have executed and delivered this Employment Agreement intending it to be madeeffective as of the Effective Date.ULTRA:ULTRA PETROLEUM CORP.,a Yukon corporationBy: Name: Brad JohnsonTitle: Interim Chief Executive OfficerEXECUTIVE: David W. HoneyfieldNOTICE PROVISION:For purposes of this Agreement, notices and all other communications provided for herein shall be in writing and shall be deemed tohave been duly given (i) when received, if delivered personally or by courier, (ii) on the date receipt is acknowledged, if delivered bycertified mail, postage prepaid, return receipt requested, or (iii) one day after transmission, if sent by facsimile transmission withconfirmation of transmission, as follows:If to Executive, at:At the most recent address in Ultra’s records.If to Ultra, at:Ultra Petroleum Corp.116 Inverness Drive East, Suite 400Englewood, Colorado 80112Attention: Chief Executive OfficerWith a copy to:Kirkland & Ellis LLP601 Lexington AvenueNew York, New York 10022Attention: Executive Compensation Group SIGNATURE PAGE TO EMPLOYMENT AGREEMENT SCHEDULE 1TAX MATTERSI.General Provisions. (A)All compensation paid or awarded to Executive hereunder shall be subject to applicable withholding, payroll andother taxes. Accordingly, with respect to any payment to be made to Executive, Ultra shall deduct, whereapplicable, any amounts authorized by Executive, and shall withhold and report all amounts required to bewithheld and reported by applicable law. (B)Capitalized terms used in this Schedule 1 but not defined herein have the meanings set forth in the EmploymentAgreement to which this Schedule 1 is attached and into which it is incorporated. (C)The term “Code,” as used herein, means the Title 26 of the United States Code, commonly referred to as theInternal Revenue Code of 1986, as amended.II.Regarding Excise Taxes. (A)If Executive is a “disqualified individual” (as defined in Section 280G(c) of the Code), and the payments andbenefits provided for in this Agreement, together with any other payments and benefits which Executive has theright to receive from Ultra or any Subsidiary, would constitute a “parachute payment” (as defined in Section280G(b)(2) of the Code), then notwithstanding anything herein to the contrary, the payments and benefits providedfor in this Agreement shall be either (a) reduced (but not below zero) so that the present value of such totalamounts and benefits received by Executive from Ultra and its affiliates will be one dollar ($1.00) less than threetimes Executive’s “base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portion of suchamounts and benefits received by Executive shall be subject to the excise tax imposed by Section 4999 of theCode or (b) paid in full, whichever produces the better net after-tax position to Executive (taking into account anyapplicable excise tax under Section 4999 of the Code and any other applicable taxes). (B)The reduction of payments and benefits hereunder, if applicable, shall be made by reducing, first, payments orbenefits to be paid in cash hereunder in the order in which such payment or benefit would be paid or provided(beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary,through to such payment or benefit that would be made first in time) and, then, reducing any benefit to beprovided in-kind hereunder in a similar order. (C)The determination as to whether any such reduction in the amount of the payments and benefits providedhereunder is necessary shall be made by Ultra in good faith. If a reduced payment or benefit is made or providedand through error or otherwise that payment or benefit, when aggregated with other payments and benefits fromUltra (or its affiliates) used in determining if a “parachute payment” exists, exceeds one dollar ($1.00) less thanthree times Executive’s base amount, then Executive shall immediately repay such excess to Ultra uponnotification that an overpayment has been made.Schedule 1 – Page 1 of 4  (D)Nothing in this Agreement, including the foregoing paragraphs (A) through (C), shall require Ultra to beresponsible for, or have any liability or obligation with respect to, Executive’s excise tax liabilities under Section4999 of the Code, if any.REGARDING CODE SECTION 409AIII.Statement of Intent. The provisions of this Schedule 1 shall apply solely to the extent that a payment under this Agreementis subject to Section 409A of the Code and the regulations and guidance promulgated thereunder (collectively, “Section409A”). The intent of the parties to this Agreement is that the payments and benefits under this Agreement comply with or beexempt from Section 409A including, but not limited to, the exemptions from the application of Section 409A providedunder Treasury Regulations Sections 1.409A-1(b)(4), 1.409A-1(b)(5), and 1.409A-(b)(9) and this Agreement will beconstrued to the greatest extent possible as consistent with those provisions. The commencement of payment or provision ofany payment or benefit under this Agreement shall be deferred to the minimum extent necessary to prevent the imposition ofany excise taxes on Ultra or Executive.IV.Notification; Reformation. If Executive receives advice, from an attorney with demonstrable tax expertise, that anyprovision of this Agreement would cause Executive to incur any additional tax or interest under Section 409A (withspecificity as to the reason therefor), and notifies Ultra thereof, or if Ultra independently makes such determination, thenUltra may, to the extent possible and after consulting with Executive, reform such provision to try to comply with Section409A through good faith modifications to the minimum extent reasonably appropriate to conform with Section 409A. To theextent that any provision hereof is modified in order to comply with or be exempt from Section 409A, such modificationshall be made in good faith and shall, to the maximum extent reasonably possible, maintain the original intent and economicbenefit to Executive and Ultra of the applicable provision without violating the provisions of Section 409A.V.Annual Cash Incentive Payments. Any Cash Incentive that Executive is awarded or becomes entitled to receive pursuant toSection 4(b) of the Agreement will be paid during the calendar year immediately following the calendar year to which suchCash Incentive relates and will be paid to Executive as soon as administratively feasible following preparation of Ultra’sunaudited financial statements for the applicable calendar year.VI.Separation from Service. (A)If any payment, compensation or other benefit provided to Executive under this Agreement in connection with a“separation from service” (within the meaning of Section 409A(a)(2)(A)(i)) is determined, in whole or in part, toconstitute “nonqualified deferred compensation” (within the meaning of Section 409A) and Executive is a“specified employee” (as defined in Section 409A(2)(B)(i)) at the time of the separation from service, thennotwithstanding anything in the Agreement to the contrary, no part of any such payments shall be paid toExecutive before the earlier of (i) the day that is six (6) months plus one (1) day after the date of the separationfrom service (the “New Payment Date”), (ii) the date of Executive’s death, or (iii) any date that otherwise complieswith Section 409A. (B)The aggregate of any payments and benefits that otherwise would have been paid and/or provided to Executiveduring the period between the date of the separation from service and the New Payment Date shall be paid toExecutive in a lump sum on the date Ultra’s first regular payroll is made following the New Payment Date, and nointerest will be paidSchedule 1 – Page 2 of 4  by Ultra with respect to any such payments and benefits. Thereafter, any payments and/or benefits that remainoutstanding as of the day immediately following the New Payment Date shall be paid without delay over the timeperiod originally scheduled, in accordance with the terms of this Agreement. (C)For purposes of Section 409A, Executive’s right to receive any installment payments pursuant to this Agreementshall be deemed to be and shall be treated as a right to receive a series of separate and distinct payments.Whenever a payment under this Agreement specifies a payment period with reference to a number of days (e.g.,payment shall be made within thirty (30) days), the actual date of payment within such period shall be within thesole discretion of Ultra. (D)Notwithstanding anything to the contrary herein, to the extent that the foregoing delay applies to the provision ofany ongoing welfare benefits, Executive shall pay the full cost of premiums for such welfare benefits due andpayable prior to the New Payment Date, and Ultra shall pay Executive an amount equal to the amount of suchpremiums which otherwise would have been paid by Ultra during such period on the date Ultra’s first regularpayroll is made following the New Payment Date. (E)A termination of employment shall not be deemed to have occurred for purposes of any provision of thisAgreement providing for the payment of any amounts or benefits subject to Section 409A upon or following atermination of employment unless such termination is also a “separation from service” (within the meaning ofSection 409A), and for purposes of any such provision of this Agreement, references in the Agreement to a“resignation,” “termination,” “resign,” “terminate,” “resignation of employment,” “termination of employment” orother like terms shall mean “separation from service” (within the meaning of Section 409A). (F)If in connection with a termination or resignation of Executive’s employment under the Agreement, Executive isrequired to execute a release to receive any payments from Ultra that constitute “nonqualified deferredcompensation” (within the meaning of Section 409A), then payments of such amounts shall not be made orcommence until the sixtieth (60th) day following such termination or resignation. Any payments suspended duringsuch 60 day period shall be paid on the date Ultra’s first regular payroll is made after the end of such period.VII.Expenses and Reimbursements. (A)This Section VII shall apply to payments of any amounts under this Agreement that are treated as “reimbursementpayments” under Section 409A. (B)All expenses or other reimbursements as provided herein shall be payable in accordance with Ultra’s policies ineffect from time to time, but in any event shall be made on or prior to the last day of the taxable year following thetaxable year in which such expenses were incurred by Executive to the extent any such payments are subject toSection 409A. Ultra shall have no obligation to reimburse Executive for any expenses submitted after the last dayof the taxable year following the taxable year in which such expenses were incurred by Executive. (C)With regard to any provision of the Agreement that provides for reimbursement of costs and expenses or in-kindbenefits, except as permitted by Section 409A: (i) the right toSchedule 1 – Page 3 of 4  reimbursement or in-kind benefits shall not be subject to liquidation or exchange for another benefit; and (ii) theamount of expenses eligible for reimbursements or in-kind benefits provided during any taxable year shall notaffect the expenses eligible for reimbursement or in-kind benefits to be provided in any other taxable year (otherthan an arrangement providing for the reimbursement of medical expenses referred to in Section 105(b) of theCode).VIII.No Representations or Warranties. (A)Nothing contained in this Agreement shall constitute any representation or warranty by Ultra or Executiveregarding compliance with Section 409A. (B)Ultra has no obligation to take any action to prevent the assessment of any excise tax under Section 409A on anyperson, and neither Ultra nor any of the Subsidiaries nor any employee or other representative of Ultra or any ofthe Subsidiaries shall have any liability to Executive with respect to any such assessment. Schedule 1 – Page 4 of 4  SCHEDULE 2EQUITY AWARD AGREEMENT [SEE ATTACHED]  RESTRICTED STOCK UNIT AGREEMENT(“AGREEMENT”)PURSUANT TO THE ULTRA PETROLEUM 2017 STOCK INCENTIVE PLAN, AS AMENDED AND RESTATED EFFECTIVE JUNE 8, 2018Name of Participant:David W. Honeyfield (“Participant”)Date of Grant of RSUs:November [●], 2018 (“Grant Date”)Restricted Stock Units Granted:613,584 (the “Target Number”)The Compensation Committee of the Board of Directors of Ultra Petroleum Corp., a Yukon corporation (the “Company”) hasapproved an award of restricted stock units (“RSUs”) to you, an employee of Ultra Resources, Inc. (“Employer”), and the Companydoes hereby grant to you, as of the Grant Date specified above, the number of RSUs specified above. The RSUs will only vest to theextent provided in and subject to the conditions described in the attached Schedule 1.Please indicate your acceptance of this Agreement by signing below, and then returning the original to our Vice President of HumanResources, Ms. Jill R. Sanford.You should keep a copy of this Agreement for your records.ULTRA PETROLEUM CORP.By: Brad JohnsonInterim Chief Executive OfficerAGREED AND ACCEPTED:Participant: DAVID W. HONEYFIELDSignature:____________________ Schedule 2 – Page 2 1.Incorporation By Reference; Plan Document. Except as provided herein, thisAgreement is subject in all respects to the terms and provisions of the Plan (including,without limitation, any amendments thereto adopted at any time and from time to timeunless such amendments are expressly intended not to apply to the Award providedhereunder), all of which terms and provisions are made a part of and incorporated inthis Agreement as if they were each expressly set forth herein. Except as providedotherwise herein, any capitalized term not defined in this Agreement shall have thesame meaning as is ascribed thereto in the Plan. Participant acknowledges the Plan hasbeen made available to Participant and Participant has read or could have read andunderstood the Plan.2.Grant of Award. The Company hereby grants to Participant, as of the Grant Datespecified in the Letter, the number of RSUs specified in the Letter. Except asotherwise provided by the Plan, Participant understands and agrees that nothingcontained in this Agreement provides, or is intended to provide, Participant with anyprotection against potential future dilution of Participant’s interest in the Company forany reason, and no adjustments shall be made for dividends in cash or other property,distributions or other rights in respect of the shares of common stock underlying theRSUs, except as otherwise specifically provided for in the Plan or this Agreement.3.Vesting; Forfeiture. 3.1.One-third (1/3) of the Target Number of RSUs will be subject to time-vestingconditions (the “TSUs”) and will vest in equal installments on each of the firstthree anniversaries of the first day of your employment with the Company (each,a “Vesting Date”). 3.2.In the event of Participant’s termination due to death, disability, termination bythe Company without Cause or termination by the Participant for “good reason”(if the Participant may terminate employment for “good reason” pursuant to anyemployment agreement or severance arrangement between the Employer and theParticipant), subject to executing and not revoking a customary release of claimsprovided by the Company no later than the 60th day following the Participant’stermination of employment, the Pro Rata Portion (as defined below) of the TSUsthat otherwise would have vested on the Vesting Date immediately following thedate of the Participant’s termination of employment will vest. The “Pro RataPortion” means the percentage equal to the number of days that have elapsedsince the later of the Grant Date or most recent Vesting Date to the Participant’sdate of termination, divided by 365 All RSUs that have time vested inaccordance with Section 3.1 or Section 3.2 hereof, a “Vested TSU”. 3.3.Two-thirds (2/3) of the Target Number of RSUs will be subject to both time-based and performance-based vesting (the “PSUs”). The PSUs will performance-vest based on the extent to which the Performance Criterion outlined in Exhibit Aare satisfied on or before the third anniversary of the Grant Date (such three-yearperiod, the “Performance Period”). 3.4.All PSUs that have not fully vested as of Participant’s date of termination(determined after application of Section 3.7) shall be immediately forfeited. AnyPSU that does not performance vest prior to the conclusion of the PerformancePeriod will automatically be forfeited for no consideration at the conclusion ofthe Performance Period. 3.5.Any PSUs that performance vest during the Performance Period in accordancewith the Performance Criterion will be subject to time-based vesting inaccordance with the following schedule: (i)one-third (1/3) of any Base PSUs (as defined below) and one-fourth (1/4) ofany Supplemental PSUs (as defined below) that have previously performancevested will time-vest on the date on which such PSUs performance vest; and (ii)one-third (1/3) of any Base PSUs and one-fourth (1/4) of any SupplementalPSUs that have previously performance vested will time-vest on the first two(in the case of Base PSUs) or three (in the case of Supplemental PSUS)anniversaries of the date on which such PSUs performance vest. For thispurpose, “Base PSUs” means the number of PSUs that performance vest up to100% of the Target Number of PSUs granted hereby, and “SupplementalPSUs” means the number of PSUs that performance vest in excess of 100% ofthe Target Number of PSUs granted hereby. 3.6.Any PSU that have both performance vested and time vested (including timevesting pursuant to Section 3.7 hereof) shall be referred to herein as a “VestedPSU”. 3.7.One-hundred percent (100%) of any Base PSUs and Supplemental PSUs thathave previously performance vested will immediately vest in the event ofParticipant’s termination due to death, disability, termination by the Companywithout Cause, subject to the Participant executing and not revoking a customaryrelease of claims provided by the Company no later than the 60th day followingthe Participant’s termination of employment. Any PSUs that have notperformance-vested in accordance with Section 3.3 hereof will automaticallyexpire and terminate for no consideration as of the date of the Participant’stermination of employment.4.Payment; Withholding. 4.1.Except as otherwise provided herein or in the Plan, the Company will deliver toParticipant an amount of shares of its common stock equal to the number ofVested TSUs awarded to Participant herein no later than thirty (30) daysfollowing each applicable Vesting Date. 4.2.Except as otherwise provided herein or in the Plan, the Company will deliver toParticipant an amount of shares of its common stock equal to the number ofVested PSUs awarded to Participant herein no later than the conclusion of thefiscal quarter in which such PSU first became a Vested PSU. 4.3.Participant agrees and acknowledges that the Company has the power and right todeduct or withhold, or require Participant to remit to the Company, an amountsufficient to satisfy any federal, state, local and foreign taxes of any kind(including, but not limited to, Participant’s FICA and SDI obligations) which theCompany, in its good faith discretion, deems necessary to be withheld or remittedto comply with the Code and/or any other applicable law, rule or regulation withrespect to the RSUs, and if the withholding requirement cannot be satisfied, theCompany may otherwise refuse to issue or transfer any shares of common stockotherwise required to be issued pursuant to RESTRICTED STOCK UNIT AGREEMENT SCHEDULE 1This award described in the cover letter to which this Schedule 1 is attached (the “Letter”) is subject to the terms and conditions set forth herein and in the Plan. Definitions of certainterms used herein are in the last section hereof. Schedule 2 – Page 3  this Agreement. Without limiting the foregoing, Participant agrees that theCompany may withhold shares of common stock otherwise deliverable toParticipant hereunder with a Fair Market Value equal to Participant’s total incomeand employment taxes imposed as a result of the vesting and/or settlement of theRSUs to the extent provided in the Plan.5.Non-Transferability. 5.1.No portion of or interest in the RSUs may be sold, assigned, transferred,encumbered, hypothecated or pledged by Participant, other than to the Companyas a result of forfeiture of the RSUs as provided herein. 5.2.The Participant shall not, directly or indirectly, Transfer any shares of CommonStock acquired upon settlement of the RSUs granted hereunder, unless in eachsuch instance the Participant (or estate or legal representative) shall have firstmade an irrevocable offer to the Company for the Common Stock proposed to beTransferred. The right of first refusal must be exercised by the Company bydelivering to the Participant (or the estate or legal representative) written notice ofsuch exercise within ten (10) business days following the Company's receipt ofwritten notification of the irrevocable offer. Upon the exercise of a right of firstrefusal, the Common Stock offered to the Company shall be purchased by theCompany at the closing price per share on the day offered to the Company. Thenotice of exercise of the right of first refusal shall specify the date and locationfor the closing of such purchase, which closing shall take place no later than four(4) business days following the expiration of the ten (10) business day offerperiod. Notwithstanding the foregoing, the Participant shall not, withoutCommittee consent, directly or indirectly Transfer more than twenty-five percent(25%) of the aggregate shares of Common Stock acquired pursuant to this RSUin any fiscal quarter.6.Dividends; Rights as Stockholder. Cash dividends on the number of shares ofCommon Stock issuable hereunder shall be credited to a dividend book entry accounton behalf of Participant with respect to each RSU granted to Participant, provided thatsuch cash dividends shall not be deemed to be reinvested in shares of Common Stockand shall be held uninvested and without interest and paid in cash at the same timethat the shares of Common Stock underlying the RSUs are delivered to Participant inaccordance with the provisions hereof. Stock or property dividends on shares ofCommon Stock shall be credited to a dividend book entry account on behalf ofParticipant with respect to each RSU granted to Participant, provided that such stockor property dividends shall be paid in (i) shares of Common Stock, (ii) in the case of aspin-off, shares of stock of the entity that is spun-off from the Company, or (iii) otherproperty, as applicable and in each case, at the same time that the shares of CommonStock underlying the RSUs are delivered to Participant in accordance with theprovisions hereof. Except as otherwise provided herein, Participant shall have norights as a stockholder with respect to any shares of Common Stock covered by anyRSU unless and until Participant has become the holder of record of such shares.7.Additional Provisions. 7.1.All questions concerning the construction, validity and interpretation of thisAgreement shall be governed by, and construed in accordance with, the laws ofthe State of Texas, without regard to the choice of law principles thereof. 7.2.The Company may at any time place legends referencing any applicable federal,state or foreign securities law restrictions on all certificates, if any, representingshares of common stock issued pursuant to this Agreement. Participant shall, atthe request of the Company, promptly present to the Company any and allcertificates, if any, representing shares of common stock acquired pursuant to this Agreement in the possession of Participant in order to carry out theprovisions of this paragraph. 7.3.No waiver or non-action by either party hereto with respect to any breach by theother party of any provision of this Agreement shall be deemed or construed tobe a waiver of any succeeding breach of such provision, or as a waiver of theprovision itself. 7.4.This Agreement, together with the Plan, contains the entire agreement betweenthe parties hereto with respect to the subject matter contained herein, andsupersedes all prior agreements or prior understandings, whether written or oral,between the parties relating to such subject matter. The Compensation Committeeshall have the right, in its sole discretion, to modify or amend this Agreementfrom time to time in accordance with and as provided in the Plan. ThisAgreement may also be modified or amended by a writing signed by both theCompany and Participant. The Company shall give written notice to Participantof any such modification or amendment of this Agreement as soon as practicableafter the adoption thereof. 7.5.Any notice hereunder by Participant shall be given to the Company in writingand such notice shall be deemed duly given only upon receipt thereof by theDirector of Human Employer and the General Counsel of the Company. Anynotice by the Company shall be given to Participant in writing and such noticeshall be deemed duly given only upon receipt thereof at such address asParticipant may have on file with the Company. 7.6.Any questions as to whether and when there has been a Termination and thecause of such Termination shall be determined in the sole discretion of theCommittee. Nothing in this Agreement shall interfere with or limit in any way theright of the Company, its Subsidiaries or its Affiliates to terminate Participant’semployment or service at any time, for any reason and with or without Cause. 7.7.Participant unambiguously authorizes, agrees and consents to transmission by theCompany (or any Subsidiary) of any personal data information related to theRSUs awarded under this Agreement for legitimate business purposes (including,without limitation, the administration of the Plan). This consent and authorizationis freely given. 7.8.The grant of RSUs and the issuance of shares of common stock hereunder shallbe subject to, and shall comply with, any applicable requirements of any foreignand U.S. federal and state securities laws, rules and regulations (including,without limitation, the provisions of the Securities Act, the Exchange Act and ineach case any respective rules and regulations promulgated thereunder) and anyother applicable law, rule, regulation or exchange requirement. The Companyshall not be obligated to issue RSUs or shares of common stock pursuant to thisAgreement if any such issuance would violate any such requirements. As acondition to settlement of the RSUs, the Company may require Participant tosatisfy any qualifications necessary or appropriate to evidence compliance withany applicable law or regulation. 7.9.This Agreement shall inure to the benefit of, be binding upon, and beenforceable by the Company and its successors and assigns. Participant shall notassign any part of this Agreement without the prior express written consent of theCompany. 7.10.The titles and headings herein are for convenience of reference only and shallnot be deemed to be a part of this Agreement. 7.11.This Agreement may be executed in one or more counterparts, each of whichshall be deemed to be an Schedule 2 – Page 4  original, but all of which shall constitute one and the same instrument. 7.12.Each party hereto shall do and perform (or shall cause to be done andperformed) all such further acts and shall execute and deliver all such otheragreements, certificates, instruments and documents as either party heretoreasonably may request in order to carry out the intent and accomplish thepurposes hereof and the consummation of the transactions contemplated in thisAgreement and the Plan; provided that no such additional documents shallcontain terms or conditions inconsistent with the terms and conditions of thisAgreement. 7.13.The invalidity or unenforceability of any provisions of this Agreement in anyjurisdiction shall not affect the validity, legality or enforceability of theremainder of this Agreement in such jurisdiction or the validity, legality orenforceability of any provision of this Agreement in any other jurisdiction, itbeing intended that all rights and obligations of the parties hereunder shall beenforceable to the fullest extent permitted by law. 7.14.Participant acknowledges and agrees that: (a) the Company may terminate oramend the Plan at any time; (b) the award of RSUs made under this Agreement iscompletely independent of any other award or grant and is made at the solediscretion of the Company; (c) no past grants or awards (including, withoutlimitation, the RSUs awarded hereunder) give Participant any right to any grantsor awards in the future whatsoever; and (d) any benefits granted under thisAgreement are not part of Participant’s ordinary salary, and shall not beconsidered as part of such salary in the event of severance, redundancy orresignation.8.Definitions. Certain terms used herein are defined in the Plan. Certain other terms aredefined below: 8.1.“Code” means the Internal Revenue Code of 1986, as amended. 8.2.“Employer” means Ultra Resources, Inc. 8.3.“Participant” is defined in the Letter. 8.4.“Plan” means the Ultra Petroleum Corp. 2017 Stock Incentive Plan as dated andamended and restated effective as of June 8, 2018. Schedule 2 – Page 5  EXHIBIT APERFORMANCE CRITERIONDuring the Performance Period, the PSUs subject to this Agreement will performance vest based on the “60-Day VWAP” (as defined below) as follows: •25% of the Base PSUs will performance-vest if the 60-Day VWAP is above $2.50; •an additional 25% of the Base PSUs will performance-vest if the 60-Day VWAP is above $5.00 (for anaggregate of 50% of the PSUs); •an additional 25% of the Base PSUs will performance-vest if the 60-Day VWAP is above $7.50 (for anaggregate of 75% of the PSUs); •the remaining 25% of the Base PSUs granted will performance-vest if the 60-Day VWAP is above $10.00 (foran aggregate of 100% of the PSUs); •an additional 25% of the Supplemental PSUs will performance-vest if the 60-Day VWAP is above $12.50 (foran aggregate of 125% of the PSUs); •an additional 25% of the Supplemental PSUs will performance-vest if the 60-Day VWAP is above $15.00 (foran aggregate of 150% of the PSUs); •an additional 25% of the Supplemental PSUs will performance-vest if the 60-Day VWAP is above $17.50 (foran aggregate of 175% of the PSUs); and •the remaining 25% of the Supplemental PSUs will performance-vest if the 60-Day VWAP is above $20.00(for an aggregate of 200% of the PSUs). ADDITIONAL PROVISIONS AND CLARIFICATIONS:1.As used herein, the term “60-Day VWAP” means, as of any date, the volume-weighted average price per share of the common stock of Ultra PetroleumCorp. measured from 9:30 am eastern time on the trading day that is sixty (60) trading days preceding such date to 4:00 pm eastern time on the tradingday immediately preceding such date.2.For the sake of clarity, the PSUs that performance vest pursuant to the first four bullets above are Base PSUs and the PSUs that performance vestpursuant to the last four bullets above are Supplemental PSUs (as those terms are used in Schedule 1 to the RSU Agreement). Schedule 2 – Page 6 Exhibit 10.38ULTRA PETROLEUM CORP.DIRECTORS DEFERRED COMPENSATION PLAN1.Establishment. Ultra Petroleum Corp., a Yukon, Canada corporation (the “Company”), hereby adopts and establishes anunfunded deferred compensation plan for non-employee directors of the Company, which shall be known as the Ultra PetroleumNonqualified Deferred Compensation Plan (the “DCP”). The DCP is a sub-plan under the Ultra Petroleum 2017 Stock Incentive Plan(the “Plan”).2.Purpose. The purpose of the DCP is to provide each non-employee director of the Company the ability to deferreceipt of shares of Stock issued in respect of equity-based awards received by such non-employee director for her or his service to theCompany until a future date chosen by such non-employee director.3.Incorporation By Reference; Plan Document Receipt. This DCP is subject in all respects to the terms and provisions of thePlan (including, without limitation, any amendments thereto adopted at any time and from time to time unless such amendments areexpressly intended not to apply hereunder), all of which terms and provisions are made a part of and incorporated into this DCP as ifthey were each expressly set forth herein. Except as provided otherwise herein, any capitalized term not defined in this DCP shallhave the same meaning as is ascribed thereto in the Plan. The Participant hereby acknowledges receipt of a true copy of the Plan andthat the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of thisDCP and the terms of the Plan, the terms of the Plan shall control.4.Definitions.“Acceleration Events” is defined in Section 11.1 hereof.“Account” means a hypothetical bookkeeping account established in the name of each Participant andmaintained by the Company to reflect the Participant’s interests under the DCP. “Beneficiary” means any person or entity, designated in accordance with Section 13.6, entitled to receivebenefits which are payable upon or after a Participant’s death pursuant to the terms of the DCP.“Deferral Election” means an election by an Eligible Director to defer Equity Compensation. A Participantshall make a new Deferral Election with respect to each Plan Year. “Distribution Date” means a date specified by a Participant in his or her Election Notice for the payment of allor a portion of such Participant’s Account.“Effective Date” means the date on which the DCP is approved by the Company’s Board of DirectorsPage 1 of 11 “Election Notice” means the notice or notices provided from time to time by the Committee for makingDeferral Elections under the DCP. The Election Notice includes the amount or percentage of Equity Awards; the DistributionDate(s); and the form of payment. Each Election Notice shall be substantially in the form of the notice attached hereto andincorporated herein as Exhibit “A” but with such modifications as are reasonable and appropriate based on applicable facts andcircumstances established by the Committee. Each Election Notice shall become irrevocable as of the last day of the ElectionPeriod.“Election Period” means the period established by the Committee with respect to each Plan Year duringwhich Deferral Elections for such Plan Year must be made in accordance with the requirements of Section 409A of the Code, asfollows:(a)General Rule. Except as provided in (b) below, the Election Period shall end nolater than the last day of the Plan Year immediately preceding the Plan Year to which the Deferral Election relates.(b)Newly Eligible Directors. The Election Period for newly Eligible Directors shallend no later than thirty (30) days after the non-employee director first becomes eligible to participate in the DCP andshall apply only with respect to compensation earned after the date of the Deferral Election.“Eligible Director” means each non-employee director of the Company. “Equity Compensation” means any equity-based incentive compensation awards received by a Participant forhis or her service as a Director pursuant to the Plan or any successor thereto. “Participant” means an Eligible Director who elects to participate in the DCP by filing an Election Notice inaccordance with Section 6.1 and any former Eligible Director who continues to be entitled to a benefit under the DCP.“DCP” means this Ultra Petroleum Nonqualified Deferred Compensation Plan, as amended from time to time.“Plan Year” means the calendar year. “Separation from Service” has the meaning set forth in Section 409A(a)(2)(A)(i) of the Code and Treas. Reg.Section 1.409A-1(h).“Unforeseeable Emergency” means a severe financial hardship of the Participant resulting from (a) an illnessor accident of the Participant, the Participant’s spouse, or the Participant’s dependent; (b) a loss of the Participant’s property dueto casualty; or (c) such other similar extraordinary and unforeseeable circumstances arising as a result of events beyond thecontrol of the Participant, all as determined in the sole discretion of the Committee.5.Eligibility; Participation. Any Eligible Director may participate in the DCP commencing as of the date on which he or shebecomes an Eligible Director. An EligiblePage 2 of 11 Director may become a Participant in the DCP by making a Deferral Election in accordance with Section 6.6.Election Procedures.6.1Deferral Election. An Eligible Director may elect to defer Equity Compensation by completing an Election Noticeand filing it with the Committee during the Election Period. The Election Notice must specify:(a)The number of shares of Stock or percentage of Equity Compensation to bedeferred;(b)The Distribution Date for the Participant’s Account (subject to the provisions ofthe DCP); and(c)The form of payment for the Participant’s Account.6.2Equity Compensation Deferrals. A Participant may elect to defer receipt of up to 100% of the Participant’s EquityCompensation for any Plan Year by making a Deferral Election in accordance with this Section 6. Equity CompensationDeferrals shall be credited to the Participant’s Account as of the date the deferred Equity Compensation otherwise would havebeen settled. In the event a Participant elects to defer receipt of the Participant’s Equity Compensation, such election mustprovide for the deferral of Equity Compensation for a minimum of three (3) years and may provide for the deferral of EquityCompensation for a maximum of five (5) years.7.Accounts and Investment Options.7.1Establishment of Accounts. The Company shall establish and maintain an Account for each Participant. TheCompany may establish more than one Account on behalf of any Participant as deemed necessary by the Committee foradministrative purposes.7.2Crediting of Account. The Committee will credit to the Participant’s Account a number of Restricted Stock Unitsequal to the number of shares of Stock otherwise deliverable to the Participant in respect of the deferred Equity Compensationabsent such Participant’s Deferral Election. The number of Restricted Stock Units credited to a Participant’s Account are subjectto adjustment in accordance with Section 7.6 of the Plan.7.3Dividend Equivalents. As of the date of payment of any cash dividend on shares of Stock (if any), the Committeewill credit to the stock account a number of shares of Stock equal to the cash dividend per share times the number of sharescredited to the stock account as of the dividend record date divided by the Fair Market Value of the Stock. As of the date ofpayment of any stock dividend on Stock, the Committee will credit to the Account a number of Restricted Stock Units equal tothe stock dividend declared times the number of Restricted Stock Units credited to the Account as of the dividend record date. 7.4Nature of Accounts. The Account is maintained for bookkeeping purposes only. Restricted Stock Units credited tothe Account are not considered actual shares ofPage 3 of 11 Stock of the Company for any purpose and a Participant will have no rights as a stockholder with respect to the same. Shareswill include fractional Restricted Stock Units computed to three decimal places.8.Vesting. Participants shall be fully vested at all times in their Equity Compensation deferrals and any Dividend equivalentsmade with respect thereto.9.Payment of Participant Accounts.9.1In General. Payment of a Participant’s Account shall be made on the earliest to occur of the following events (each a“Payment Event”):(a)The Distribution Date specified in the Participant’s Deferral Election; providedthat, the Participant must select from among the available Distribution Date(s) designated by the Committee and set forthin the Election Notice;(b)The Participant’s Separation from Service;(c)The Participant’s death;(d)The Participant’s Disability; and(e)The occurrence of a Change in Control.9.2Timing of Payments. Except as otherwise provided in this Section 9, payments shall be made or commence within 10business days following a Payment Event.9.3Form of Payment. Each Participant shall specify in his or her Election Notice the form of payment for amounts in hisor her Account that are covered by the election. In the absence of a valid election with respect to form of payment, amounts willbe paid in a single lump sum.9.4Medium of Payment. Each Participant shall specify in his or her Election Notice the medium ofpayment for amounts in his or her Account that are covered by the election from the following two alternatives:(a)in shares of Stock; or(b)in the following two components (i) an amount in cash equal to the Fair MarketValue of the Restricted Stock Unit subject to the applicable Deferral Election at the time of the Payment Eventmultiplied by the then-effective highest marginal federal and state income tax rate applicable to the Participant, and (ii) anumber of shares of Stock equal to the remaining number of Restricted Stock Units subject to the applicable DeferralElection after payment of subsection (i) above; provided any fractional shares shall be paid in cash based on the FairMarket Value of the shares of Stock at the time of the Payment Event.Page 4 of 11 In the absence of a valid election with respect to medium of payment, amounts will be paid in shares of Stock.10.Payments Due to Unforeseeable Emergency.10.1Request for Payment. If a Participant suffers an Unforeseeable Emergency, he or she may submit a written requestto the Committee for payment of his or her Account.10.2No Payment If Other Relief Available. The Committee will evaluate the Participant’s request for payment due to anUnforeseeable Emergency taking into account the Participant’s circumstances and the requirements of Section 409A of theCode. In no event will payments be made pursuant to this Section 10 to the extent that the Participant’s hardship can be relieved:(a) through reimbursement or compensation by insurance or otherwise; or (b) by liquidation of the Participant’s assets, to theextent that liquidation of the Participant’s assets would not itself cause severe financial hardship; or (c) by the cessation ofdeferrals under the DCP.10.3Limitation on Payment Amount. The amount of any payment made on account of an Unforeseeable Emergencyshall not exceed the amount reasonably necessary to satisfy the Participant’s financial need, including amounts necessary to payany Federal, state or local income taxes or penalties reasonably anticipated to result from the payment, as determined by theCommittee.10.4Timing of Payment. Payments shall be made from a Participant’s Account as soon as practicable and in any eventwithin 10 business days following the Committee’s determination that an Unforeseeable Emergency has occurred andauthorization of payment from the Participant’s Account.11.Acceleration Events.11.1Permissible Acceleration Events. Notwithstanding anything in the DCP to the contrary but only to the extentconsistent with Section 409A, the Committee, in its sole discretion, may accelerate payment of all or a portion of a Participant’sAccount upon the occurrence of any of the events (“Acceleration Events”) set forth in this Section 11. The Committee’sdetermination of whether payment may be accelerated in accordance with this Section 11 shall be made in accordance withTreas. Reg. Section 1.409A-3(j)(4).(a)Domestic Relations Orders. The Committee may accelerate payment of aParticipant’s Account to the extent necessary to comply with a domestic relations order (as defined in Section 414(p)(1)(B) of the Code).(b)Limited Cashouts. The Committee may accelerate payment of a Participant’sAccount to the extent that (i) the aggregate amount in the Participant’s Account does not exceed the applicable dollaramount under Section 402(g)(1)(B) of the Code, (ii) the payment results in the termination of the Participant’s entireinterest in the DCP and any plans that are aggregated with the DCP pursuant to Treas. Reg. Section 1.409A-1(c)(2), and(iii) the Committee’s decision to cash out the Participant’s Account is evidenced in writing no later than the date ofpayment.Page 5 of 11 (c)Payment Upon Income Inclusion. The Committee may accelerate payment of allor a portion of a Participant’s Account to the extent that the DCP fails to meet the requirements of Section 409A of theCode; provided that, the amount accelerated shall not exceed the amount required to be included in income as a result ofthe failure to comply with Section 409A of the Code.(d)Termination of the DCP. The Committee may accelerate payment of all or aportion of a Participant’s Account upon termination of the DCP in accordance with Treas. Reg. Section 1.409A-3(j)(4)(ix).(e)Certain Offsets. The Committee may accelerate payment of all or a portion of theParticipant’s Account to satisfy a debt of the Participant to the Company incurred in the ordinary course of the servicerelationship between the Company and the Participant; provided, however, the amount accelerated shall not exceed$5,000 and the payment shall be made at the same time and in the same amount as the debt otherwise would have beendue and collected from the Participant.(f)Bona Fide Disputes as to Right to Payment. The Committee may acceleratepayment of all or a portion of a Participant’s Account where the payment is part of a settlement between the Companyand the Participant of an arm’s length, bona fide dispute as to the Participant’s right to the deferred amount.12.Amendment and Termination.12.1The Board may, at any time, and in its discretion, alter, amend, modify, suspend or terminate theDCP or any portion thereof; provided, however, that no such amendment, modification, suspension or termination shall, withoutthe consent of a Participant, adversely affect such Participant’s rights with respect to amounts credited to or accrued in his or herAccount and provided, further, that, no payment of benefits shall occur upon termination of the DCP unless the requirements ofSection 409A of the Code have been met.13.Miscellaneous.13.1No Service Rights. Nothing in the DCP or any instrument executed pursuant thereto shall confer upon anyParticipant any right to continue to serve the Company or interfere in any way with the right of the Company to terminate theParticipant’s service at any time with or without notice and with or without cause.13.2Governing Law. The DCP shall be administered, construed and governed in all respects under and by the laws ofthe state of Texas, without reference to the principles of conflicts of law (except and to the extent superseded by applicableFederal law).13.3Section 409A of the Code. The Company intends that the DCP comply with the requirements of Section 409A ofthe Code and shall be operated and interpreted consistent with that intent. Notwithstanding the foregoing, the Company makesno representation that the DCP complies with Section 409A of the Code and shall have no liability to any Participant for anyfailure to comply with Section 409A of the Code.Page 6 of 11 13.4General Assets/Trust. All amounts provided under the DCP shall be paid from the general assets of the Companyand no separate fund shall be established to secure payment. Notwithstanding the foregoing, the Company may, but need not,establish a rabbi trust to assist it in funding any DCP obligations.13.5No Warranties. Neither the Company nor the Committee warrants or represents that the value of any Participant’sAccount will increase. Each Participant assumes the risk in connection with the deemed investment of his or her Account.13.6Beneficiary Designation. Each Participant under the DCP may from time to time name any beneficiary orbeneficiaries to receive the Participant’s interest in the DCP in the event of the Participant’s death. Each designation will revokeall prior designations by the same Participant, shall be in a form reasonably prescribed by the Committee and shall be effectiveonly when filed by the Participant in writing with the Company during the Participant’s lifetime. If a Participant fails to designatea beneficiary, then the Participant’s designated beneficiary shall be deemed to be the Participant’s estate.13.7No Assignment. Neither a Participant nor any other person shall have any right to sell, assign, transfer, pledge,anticipate or otherwise encumber, transfer, hypothecate or convey any amounts payable hereunder prior to the date that suchamounts are paid (except for the designation of beneficiaries pursuant to Section 13.6).13.8Expenses. The costs of administering the DCP shall be paid by the Company.13.9Severability. If any provision of the DCP is held to be invalid, illegal or unenforceable, whether in whole or in part,such provision shall be deemed modified to the extent of such invalidity, illegality or unenforceability and the remainingprovisions shall not be affected.13.10Headings and Subheadings. Headings and subheadings in the DCP are for convenience onlyand are not to be considered in the construction of the provisions hereof.* * * * *IN WITNESS WHEREOF, ULTRA PETROLEUM CORP. has adopted this DCP as of the Effective Date written above. ULTRA PETROLEUM CORP. By: _______________________________Name: Title: Page 7 of 11 EXHIBIT “A”TOULTRA PETROLEUM CORP.DIRECTORS DEFERRED COMPENSATION PLANFORM OF ELECTION NOTICEThis Election Notice must be completed and returned to [________________] at Ultra Petroleum Corp. (the “Company”)by no later than December 31, [______] (the “Election Deadline”); provided, that, if you are a newly Eligible Director, as determinedby the Committee, the Election Deadline is the 30th day after the later of the Effective Date of the DCP and the date you become anEligible Director. Your election becomes irrevocable as of the Election Deadline.Pursuant to the terms of the Ultra Petroleum Nonqualified Deferred Compensation Plan (the “DCP”), I hereby elect to defercertain of my compensation for the [______] Plan Year in accordance with this election. Capitalized terms used but not defined hereinhave the meanings set forth in the DCP.Equity Compensation Deferral ElectionPursuant to Section 6 of the DCP, I hereby elect to defer (select either a percentage or number of shares of Restricted StockUnits):_____ percent (_____%) of; or _____ shares of Restricted Stock Units deliverable pursuant to my Equity Compensation, ifany, for the [_____] Plan Year in accordance with this election.Distribution Date ElectionI hereby elect the following Distribution Date with respect to deferrals made hereunder: January 2, [______].AMOUNTS DEFERRED HEREUNDER MUST BE DEFERRED A MINIMUM OF 3 YEARS (BUT NO MORETHAN 5 YEARS) AFTER THE YEAR IN WHICH THE EQUITY COMPENSATION IS MADE AND THE DISTRIBUTIONDATE SHALL BE ON JANUARY 2 OF THE APPLICABLE YEAR: FOR EXAMPLE, AWARDS ISSUED IN 2018 MUSTBEPage 8 of 11 DEFERRED UNTIL JANUARY 2, 2021, OR SUCH LATER DISTRIBUTION DATE AS THE DIRECTOR MAY SOCHOOSE, BUT NO LATER THAN JANUARY 2, 2023.Other Payment EventsNotwithstanding the above Distribution Date election, if any of the following Payment Events occurs prior to theDistribution Date, payment shall be made in accordance with Section 9 of the DCP: •Your Separation from Service. •Your death. •Your Disability. •A Change in Control.Form of PaymentI understand that my account will be paid in one (1) lump sum payment with respect to amounts deferred hereunder. Medium of PaymentI hereby elect to receive my payment with respect to amounts deferred hereunder in one of the following two alternatives(check one):________ When due, the payment shall be made wholly in shares of Stock.________ When due, the payment shall be made in two forms: (i) an amount in cash equal to the Fair Market Value of theRestricted Stock Units subject to this deferral election at the time of the Payment Event multiplied by the then-effective highestmarginal federal and state income tax rate applicable to me and (ii) a number of shares of Stock equal to the remaining number ofRestricted Stock Units subject to this deferral election after payment of subsection (i) above.Section 409A of the CodeI understand that the DCP is intended to comply with Section 409A of the Code and that it will be interpreted accordingly.However, I also understand that the Company will have no liability with respect to any failure to comply with Section 409A of theCode.Subsequent Plan YearsI understand that this Deferral Election applies only with respect to compensation earned for services performed during the[______] Plan Year. I hereby acknowledge that if I wish to defer any of my compensation with respect to future Plan Years, I willneed to make a newPage 9 of 11 Deferral Election by completing another Election Notice and submitting it to the Committee on or before the Election Deadline forsuch Plan Year.AcknowledgementBy executing this Election Notice I acknowledge that: •I have read and understand the terms of the DCP and agree to all of its terms and conditions. •I understand that any amounts I defer hereunder are unfunded and unsecured and subject to the claims of theCompany’s creditors in the event of the Company’s insolvency. •I have consulted with my own tax advisor regarding the tax consequences of participating in the DCP and makingthis election.* * * * * Page 10 of 11 I hereby make this election as of this ____ day of ________________, ______.________________________________Participant’s Signature________________________________Print Participant’s Name________________________________ Copy received this _____ day of____________, ______.__________________________________[Committee Member] Page 11 of 11Exhibit 10.38  Exhibit 21.1 LIST OF SUBSIDIARIES OF ULTRA PETROLEUM CORP. Entity Jurisdiction ofOrganization UP Energy Corporation Delaware Ultra Resources, Inc. Delaware Ultra Wyoming, LLC Delaware UPL Pinedale, LLC Delaware UPL Three Rivers Holdings, LLC Delaware Ultra Wyoming LGS, LLC Delaware Keystone Gas Gathering, LLC Delaware Exhibit 23.1CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSNetherland, Sewell & Associates, Inc. has issued a report, as of December 31, 2018, of the “Estimates of Reserves and Future Revenue tothe Ultra Petroleum Corp. Interest in Certain Oil and Gas Properties located in Pinedale Field, Sublette County, Wyoming as of December 31,2018” for Ultra Petroleum Corp. Netherland, Sewell & Associates, Inc. consents to the reference in Form 10-K to Netherland, Sewell & Associates,Inc.’s reserves report dated March 1, 2019, and to the incorporation by reference of our Firm’s name and report into Ultra’s previously filedRegistration Statements on Form S-1 and Form S-1A (File No. 333-217481) and Form S-8 (File No. 333-217268). NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ C. H. (Scott Rees) IIIC.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer Dallas, TexasMarch 7, 2019 Exhibit 23.2Consent of Independent Registered Public Accounting Firm We consent to the incorporation by reference in the following Registration Statements: (1)Registration Statement (Form S-8 No. 333-217268) pertaining to the Ultra Petroleum Corp. 2017 Stock Incentive Plan, and (2)Registration Statement (Form S-3 No. 333-217481) of Ultra Petroleum Corp.; of our reports dated March 7, 2019, with respect to the consolidated financial statements of Ultra Petroleum Corp. and subsidiaries and the effectiveness ofinternal control over financial reporting of Ultra Petroleum Corp. and subsidiaries included in this Annual Report (Form 10-K) of Ultra Petroleum Corp. forthe year ended December 31, 2018. /s/ Ernst & Young LLP Denver, ColoradoMarch 7, 2019 Exhibit 31.1CERTIFICATIONI, Brad Johnson, certify that:1. I have reviewed this Annual Report on Form 10-K of Ultra Petroleum Corp.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,particularly during the period in which this report is being prepared;(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrols over financial reporting. /s/ Brad JohnsonBrad Johnson,President and Chief Executive Officer(Principal Executive Officer)Date: March 7, 2019Exhibit 31.2CERTIFICATIONI, David W. Honeyfield, certify that:1. I have reviewed this Annual Report on Form 10-K of Ultra Petroleum Corp.;2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,particularly during the period in which this report is being prepared;(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrols over financial reporting. /s/ David W. HoneyfieldDavid W. Honeyfield,Senior Vice President and Chief Financial Officer(Principal Financial Officer)Date: March 7, 2019Exhibit 32.1SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL EXECUTIVE OFFICERULTRA PETROLEUM CORP.In connection with the Annual Report of Ultra Petroleum Corp. (the “Company” ) on Form 10-K for the fiscal year ended December 31, 2018, as filedwith the Securities and Exchange Commission on the date hereof (the “Report” ), I, Brad Johnson, President and Chief Executive Officer of the Company,certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany. /s/ Brad JohnsonBrad Johnson,President and Chief Executive Officer(Principal Executive Officer)Dated: March 7, 2019This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-OxleyAct of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes ofSection 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporatedby reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference. Exhibit 32.2SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL FINANCIAL OFFICERULTRA PETROLEUM CORP.In connection with the Annual Report of Ultra Petroleum Corp. (the “Company” ) on Form 10-K for the fiscal year ended December 31, 2018, as filedwith the Securities and Exchange Commission on the date hereof (the “Report” ), I, David W. Honeyfield, Senior Vice President and Chief Financial Officerof the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany. /s/ David. W. HoneyfieldDavid W. Honeyfield,Senior Vice President and Chief FinancialOfficer(Principal Financial Officer)Dated: March 7, 2019This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-OxleyAct of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes ofSection 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporatedby reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference. Exhibit 99.1 March 1, 2019 Mr. Justin SandiferUltra Petroleum Corp.116 Inverness Drive East, Suite 400Englewood, Colorado 80112 Dear Mr. Sandifer: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the Ultra PetroleumCorp. (Ultra) interest in certain gas properties located in Pinedale Field, Sublette County, Wyoming. We completed our evaluation on or about thedate of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned byUltra. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and ExchangeCommission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Ultra's usein filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for suchpurpose. We estimate the net reserves and future net revenue to the Ultra interest in these properties, as of December 31, 2018, to be: Net Reserves Future Net Revenue (M$) Gas Condensate Present WorthCategory (MMCF) (MBBL) Total at 10% Proved Developed Producing 2,206,829.4 17,489.7 3,883,942.6 2,234,148.8Proved Developed Non-Producing 37,126.9 385.7 75,644.5 41,940.3Proved Undeveloped 677,876.5 5,569.4 765,256.4 159,266.9 Total Proved 2,921,832.8 23,444.8 4,724,843.5 2,435,356.0 Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Condensate volumes are expressed inthousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas equivalent volumes shown in this report are expressed inmillions of cubic feet equivalent (MMCFE), determined using the ratio of 6 MCF of gas to 1 barrel of liquids. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Asrequested, probable and possible reserves that may exist for these properties have not been included. The estimates of reserves and futurerevenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undevelopedacreage beyond those tracts for which undeveloped reserves have been estimated. Gross revenue is Ultra's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is afterdeductions for Ultra's share of production taxes, ad valorem taxes, capital costs, abandonment costs, operating expenses, and payments to netprofit interests but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent todetermine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in thisreport, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Gas prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month gas price for each month inthe period January through December 2018. For gas volumes, the average Kern River (Opal plant) spot price of $2.727 per MMBTU is adjusted forenergy content, transportation fees, and market differentials. Gas prices are held constant throughout the lives of the properties. Initialcondensate prices are based on the 12-month unweighted arithmetic average of the first-day-of-the-month condensate price for each month in theperiod January through December 2018. For condensate volumes, the average West Texas Intermediate spot price of $65.56 per barrel isadjusted for quality, transportation fees, and market differentials. In March 2019, the condensate price changes to a fixed contract price of $65.79per barrel and is held constant until contract expiration in March 2020. At contract expiration, the price is adjusted to the original average spotprice and held constant thereafter. The average adjusted product prices weighted by production over the remaining lives of the properties are$2.594 per MCF of gas and $63.49 per barrel of condensate. Operating costs used in this report are based on operating expense records of Ultra. These costs include the per-well overhead expenses allowedunder joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have beendivided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Ultra are included tothe extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation. Capital costs used in this report were provided by Ultra and are based on authorizations for expenditure and actual costs from recentactivity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding offuture development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital coststo be reasonable. Abandonment costs used in this report are Ultra's estimates of the costs to abandon the wells and production facilities, net ofany salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or conditionof the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do notinclude any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Ultrainterest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; ourprojections are based on Ultra receiving its net revenue interest share of estimated future gross production. Additionally, we have made nospecific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include theeffects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accountingstatements. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oiland gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be commercially recoverable;probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimatesof reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoirperformance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, butnot limited to, that the properties will be developed consistent with current development plans as provided to us by Ultra, that the properties will beoperated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that ourprojections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costsrelated thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, thesales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparingthis report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data,production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated usingdeterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil andGas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geosciencemethods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriateand necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gasevaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarilyrepresent only informed professional judgment. The data used in our estimates were obtained from Ultra, other interest owners, various operators of the properties, public data sources, and thenonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in ouroffice. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technicalpersons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence,objectivity, and confidentiality set forth in the SPE Standards. Sean A. Martin, a Licensed Professional Engineer in the State of Texas, has beenpracticing consulting petroleum engineering at NSAI since 2014 and has over 7 years of prior industry experience. Philip R. Hodgson, a LicensedProfessional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 yearsof prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interestin these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees IIIBy:C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer /s/ Sean A. Martin/s/ Philip R. HodgsonBy:By:Sean A. Martin, P.E. 125354Philip R. Hodgson, P.G. 1314Petroleum EngineerVice President Date Signed: March 1, 2019Date Signed: March 1, 2019 Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital documentis intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditionsstated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede thedigital document. SAM:CDC DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included issupplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASBAccounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase orlease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs,and other costs incurred in acquiring properties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth,temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogousreservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii)Same environment of deposition; (iii)Similar geological structure; and (iv)Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually containssulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, whenproduced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from thegeoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minorcompared to the cost of a new well; and (ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means notinvolving a well. Supplemental definitions from the 2018 Petroleum Resources Management System:Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of theestimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals thatare open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3)wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will requireadditional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiatedor restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil andgas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs ofdevelopment activities, are costs incurred to: (i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific developmentdrilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary indeveloping the proved reserves. (ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of wellequipment such as casing, tubing, pumping equipment, and the wellhead assembly. Definitions - Page 1 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, andproduction storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv)Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. Asexamples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group ofseveral fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or isreasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oiland gas producing activities as defined in paragraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of thatdate. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to haveprospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs maybe incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types ofexploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and otherexpenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geologicaland geophysical or "G&G" costs. (ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense,and the maintenance of land and lease records. (iii)Dry hole contributions and bottom hole contributions. (iv)Costs of drilling and equipping exploratory wells. (v)Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gasin another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well asthose items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/orstratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by localgeologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operationalfield. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broaderterms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i)Oil and gas producing activities include: (A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states andoriginal locations; (B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gasfrom such properties; (C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including theacquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1)Lifting the oil and gas to the surface; and (2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and Definitions - Page 2 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewablenatural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to suchextraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve onthe lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for theproduction function as: a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marineterminal; and b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to apurchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, amarine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable inthe state in which the hydrocarbons are delivered. (ii)Oil and gas producing activities do not include: (A)Transporting, refining, or marketing oil and gas; (B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does nothave the legal right to produce or a revenue interest in such production; (C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gascan be extracted; or (D)Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding provedplus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the totalquantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of availabledata are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly thearea and vertical limits of commercial production from the reservoir by a defined project. (iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than therecovery quantities assumed for probable reserves. (iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technicaland commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results insuccessful similar projects. (v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the sameaccumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geologicaldiscontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are incommunication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than theproved area if these areas are in communication with the proved reservoir. (vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potentialexists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKOonly if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meetthis reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressuregradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together withproved reserves, are as likely as not to be recovered. (i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimatedproved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantitiesrecovered will equal or exceed the proved plus probable reserves estimates. Definitions - Page 3 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of availabledata are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certaintycriterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communicationwith the proved reservoir. (iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than assumed for proved reserves. (iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occurfor each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associatedprobabilities of occurrence. (20) Production costs. (i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs ofsupport equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. Theybecome part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A)Costs of labor to operate the wells and related equipment and facilities. (B)Repairs and maintenance. (C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E)Severance taxes. (ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, andmarketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciationand applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, andamortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oiland gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data,can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidenceindicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extractthe hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i)The area of the reservoir considered as proved includes: (A)The area identified by drilling and limited by fluid contacts, if any, and (B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or gas on the basis of available geoscience and engineering data. (ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in awell penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonablecertainty. (iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associatedgas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, orperformance data and reliable technology establish the higher contact with reasonable certainty. (iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluidinjection) are included in the proved classification when: (A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole,the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes the reasonable certainty of the engineering analysis on which the project or program was based; and Definitions - Page 4 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (B)The project has been approved for development by all necessary parties and entities, including governmental entities. (v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shallbe the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweightedarithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractualarrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will berecovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed theestimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability ofgeoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time,reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested andhas been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogousformation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there willexist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and allpermits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs arepenetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by anon-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e.,potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of theend of the year: a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in theoperation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed inaccordance with paragraphs 932-235-50-3 through 50-11B: a.Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-endquantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producingthe proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Ifestimated development expenditures are significant, they shall be presented separately from estimated production costs.c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration offuture tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of theproperties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oiland gas reserves.d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses fromfuture cash inflows.Definitions - Page 5 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating toproved oil and gas reserves.f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimatedto be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gasinjection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologiccondition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes testsidentified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if notdrilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wellson undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility atgreater distances. (ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they arescheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitivelocations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take intoconsideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years shouldbe the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend pastfive years include, but are not limited to, the following: ●The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wellsnecessary to maintain the lease generally would not constitute significant development activities);●The company's historical record at completing development of comparable long-term projects;●The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;●The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development planseveral times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not beappropriate); and●The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions ondevelopment on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to developproperties with higher priority). (iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection orother improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the samereservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technologyestablishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. Definitions - Page 6 of 6

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