UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

 

For the quarterly period ended September 30, 2018

or

For the transition period from                to

Commission file number 001-33614

 

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

 

(303) 708-9740

(Registrant’s telephone number, including area code)

 

400 N. Sam Houston Parkway E.

Suite 1200

Houston, Texas 77060

(Former name, former address and former fiscal year, if changed since last report)

 

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

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

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

 

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15 (d) of the Securities Exchange Act of 1934 subsequent to the distributions of securities under a plan confirmed by a court. YES ☑     NO ☐

The number of shares, without par value, of Ultra Petroleum Corp., outstanding as of October 25, 2018 was 197,053,583.

 

 

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TABLE OF CONTENTS

 

 

 

 

 

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PART I – FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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ULTRA PETROLEUM CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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ULTRA PETROLEUM CORP.

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

 

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ULTRA PETROLEUM CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

 

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

All amounts in this Quarterly Report on Form 10-Q 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”, “us”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

On September 25, 2018, the Company completed the sale of its Utah assets to an unnamed third party for net cash proceeds of $69.3 million, including management fees of $0.6 million. The divested assets consisted primarily of oil and gas properties.

1.  SIGNIFICANT ACCOUNTING POLICIES:

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018.

The condensed consolidated balance sheet at December 31, 2017, has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements.

For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2017.

(a) Basis of Presentation and Principles of Consolidation:  The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All inter-company transactions and balances have been eliminated.

(b) Cash and Cash Equivalents:  The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) Restricted Cash:  Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Restricted cash at September 30, 2017 also includes the funds which the Company deposited in a $400.0 million reserve fund pending resolution of make-whole and postpetition interest claims (see Note 9). 

The Company follows Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash and reports the change in cash, cash equivalents, and restricted cash in total on the Condensed Consolidated Statements of Cash Flows.  See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same amounts shown in the Condensed Consolidated Statements of Cash Flows.

 

 

(d) Accounts Receivable, net: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts.  The carrying amount of the Company’s accounts receivable approximates fair value

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

(e) Property, Plant and Equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

(f) Oil and Natural Gas Properties:  The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities 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 (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded 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 properties is not recognized, unless the gain or loss would 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-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. 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 be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs, as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by 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 ceiling test 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 performed quarterly, 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 in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future 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-cash charge 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 increase the ceiling.  The Company did not incur a ceiling test write-down during the nine months ended September 30, 2018 or 2017.

(g) Inventories:  Inventory primarily includes $19.0 million in pipe and production equipment that will be utilized during the 2018-2019 drilling programs and $1.2 million in crude oil inventory as of September 30, 2018.  Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location.  Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost.  The Company uses the weighted average method of recording its materials and supplies inventory.  Crude oil inventory is valued at lower of cost or market.

(h) Deferred Financing Costs: The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and includes the costs for issuing debt, including issuance discounts, except those related to the Revolving Credit Facility (as defined below), as a direct deduction from the carrying amount of the

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

related debt liability. Costs related to the issuance of the Revolving Credit Facility are recorded in Other assets in the Condensed Consolidated Balance Sheets.

(i) Derivative Instruments and Hedging Activities:  The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Condensed Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Condensed Consolidated Statements of Operations.  The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 7 for additional details.

(j) Income Taxes:  Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years 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 is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes.  In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

(k) Earnings Per Share:  Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

 

Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. For the three and nine months ended September 30, 2018, the Company had 4.9 million and 2.5 million contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met. See Note 5 for additional details.

 

 

(l) Use of Estimates:  Preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions 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.

(m) Accounting for Share-Based Compensation:  The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

(n) Fair Value Accounting:  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements.  See Note 8 for additional details.

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

(o) Asset Retirement Obligation:  The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and 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 the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling 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 Condensed Consolidated Balance Sheets.  

(p) 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.  See Note 2 for additional details and disclosures related to the Company’s adoption of this standard.

(q) Other revenues: Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed.

(r) Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

(s) Reclassifications:  Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

(t) Recent Accounting Pronouncements:

Leases.  In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”).  The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information.   For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements. To facilitate compliance with ASC 842, the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, initiated the process of reviewing its contract portfolio, and implemented appropriate changes to business systems. The Company will continue to evaluate its processes and internal controls during 2018. Additionally, we are evaluating the disclosure requirements under the new standard to ensure the appropriate information will be available for these disclosures.  While we are continuing to assess all potential impacts of the standard, we anticipate recognition of additional assets and corresponding liabilities related to leases. The overall financial impact is continuing to be evaluated by the Company.

Stock Compensation.  In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which is intended 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 of this ASU did not have a material impact on the Company’s consolidated financial statements.

Derivatives.  In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815) (“ASU No. 2017-12”), which makes significant changes 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 periods beginning after December 15, 2018, including interim periods within those annual periods.  The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements. 

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 value measurements in Topic 820. The ASU is effective for the public companies for

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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.

Revenue from Contracts with Customers.  In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers 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 sales method to account for wellhead imbalances.  The impact to revenues for the nine months ended September 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying the new revenue standard.  The comparative information has not been restated and continues to be reported under the accounting standards for those periods.  See Note 2 for additional details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

2.  IMPACT OF ASC 606 ADOPTION

 

In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated income statement for the nine months ended September 30, 2018 is as follows:

 

 

The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method.  The Company evaluated the contracts for sales of oil and natural gas utilizing the principal versus agent indicators, noting no change in revenue recognition resulted from the analysis.

 

Revenue Recognition

 

Revenue from Contracts with Customers

 

Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other 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 a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies.

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

 

Natural gas sales

We sell natural gas production at the tailgate of the processing plant or at 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, (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 at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold.  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 the transaction price; thus, they are presented as expenses in the Condensed 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.  The Company may act as an agent and market the other partners’ share of the natural gas production.  If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production.

Oil sales

We sell oil production at (a) the lease automatic custody transfer (“LACT”) meter for Wyoming condensate, (b) the tank battery for Utah wax/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 the product.  For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold.  Gathering fees are 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 nine months ended September 30, 2018, there was no change to the method used to recognize oil sales and there was no impact to the condensed consolidated financial statements 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.  The Company 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 is recorded at the Company’s net revenue interest in the production.  

 

Other revenues

Our 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 upon completion of the processing service.  The Company is considered the principal, and revenue is recognized at the point in time that the control is transferred.  In conjunction with the adoption of ASC 606, for the nine months ended September 30, 2018, there was no change to the method used to recognize other processing revenues and there was no impact to the condensed consolidated financial statements for other revenues.

 

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas imbalances, which is no longer allowed under ASC 606.  In conjunction with the adoption of ASC 606, for the nine months ended September 30, 2018, there was no material impact to the condensed consolidated financial statements due to this change in accounting for our production imbalances.

 

Transaction price allocated to remaining performance obligations

A 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 the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

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 that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

Contract balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

 

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not be received for 30 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 the price 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 the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

3.  OIL AND GAS PROPERTIES AND EQUIPMENT:

 

 

4.  DEBT AND OTHER LONG-TERM OBLIGATIONS:

 

 

 

 

 

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Ultra Resources, Inc.

Credit Agreement. In April 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Agreement (defined below)).  In September 2017, the administrative agent and the other lenders approved an increase in the borrowing base under the Credit Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the Revolving Credit Facility to an aggregate amount of $425.0 million.  In April 2018, the administrative agent and the other lenders reaffirmed the borrowing base at $1.4 billion. In September 2018, the borrowing base was reduced to $1.3 billion in connection with the semi-annual redetermination.   At September 30, 2018, Ultra Resources had no outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million and a borrowing base of $1.3 billion.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank 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 to 250 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 any fiscal 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 otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022.

The Revolving Credit Facility requires Ultra Resources 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 consolidated net leverage ratio that does not exceed  (a) 4.50 to 1.00, during the period ending on the last day of the fiscal quarter ending June 30, 2019, (b) 4.25 to 1.00, during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ending on the last day of the fiscal quarter ending December 31, 2019, and (c) 4.00 to 1.00 beginning on the last day of the fiscal quarter ending on March 31, 2020; and (iv) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.  

Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, the Company 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 the quarterly projected volumes of natural gas from PDP reserves.  Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement. The Company expects to be in compliance with these requirements while the requirements remain effective.

Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing 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 comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated.

Term Loan. In April 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million 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 drawn immediately after the funding of the initial term loan.  In September 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under the Term Loan Agreement to $975.0 million.  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 the deferred financing costs noted above.  The Term Loan Agreement has capacity to increase the commitments subject to certain conditions.  At September 30, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement, including current maturities.

The Term Loan Agreement bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points.  The Term Loan Agreement amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Agreement matures on April 12, 2024.

The Term Loan Agreement is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the 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 Loan Agreement.

The Term Loan Agreement also contains customary affirmative and negative covenants, including 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 and other customary covenants. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Senior Unsecured Notes. In April 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Unsecured Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, and the Company and its subsidiaries, as guarantors. The Unsecured Notes are treated as a single class of securities under the Indenture.

The Unsecured Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Unsecured Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act.

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 Notes will 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 Unsecured Notes from the issue date until maturity.  

Prior to April 15, 2019, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2022 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

If Ultra Resources experiences certain change of control triggering events as set forth in the Indenture, each holder of the Unsecured Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Unsecured Notes, plus any accrued but unpaid interest to the date of repurchase.

The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Unsecured Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Unsecured Notes.

The Indenture contains customary events of default. Unless otherwise noted in the Indenture, upon a continuing event of default, the trustee under the Indenture (the “Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable.

On October 17, 2018, the Company entered into an exchange agreement relating to the Unsecured Notes, as discussed further in Note 11.

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

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5.  SHARE BASED COMPENSATION:

Valuation and Expense Information 

 

 

Performance Share Plans:

2017 Stock Incentive Plan.  In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established pursuant to which 7.5% of the equity in the Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, and other employees of the Company (the “Reserve”). During 2017, Management Incentive Plan Grants (the “Initial MIP Grants”) were made to members of the board of directors (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 or exceeds $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 Initial MIP 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 volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before the fifth anniversary of the Effective Date, as defined in Note 10, such Initial MIP Grants shall automatically expire.  The balance of the Reserve is available to be granted by the Board from time to time.

On June 8, 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of the 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends and restates the 2017 Stock Incentive Plan to, among other things:

In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvested portion of their Initial MIP Grants for a 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 will vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021.

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’s total equity, for purposes of FASB ASC 718, the award is subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are subject to a market

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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condition. Unlike the valuation of an award that 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 impact of 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 estimate the fair value of the Initial MIP Grants that include a market condition prior to the modification thereof in July 2018.

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 point during 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) the award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share 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 which the market condition is satisfied. The duration is the period from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is satisfied.

Modification. The incremental expense recognized from the modification was $0.6 million for the three and nine months ended September 30, 2018.

 

Expense. For the nine months ended September 30, 2018, the Company recognized $11.5 million in pre-tax compensation expense, of which $10.9 million related to the Initial MIP Grants and is included within General and administrative expenses on the Condensed Consolidated Statement of Operations. During the nine months ended September 30, 2017, the Company recognized $34.2 million in pre-tax compensation expense, of which $32.9 million related to the Initial MIP Grants.        

6.  INCOME TAXES:

The Company’s overall effective tax rate on pre-tax income was different than the statutory rate of 21% due primarily to valuation allowances.

The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2018.  Some or all of this valuation allowance may be reversed in future periods against future income. On December 22, 2017, the Tax Cuts and Jobs Act (“TCJA”) was enacted into law.  The legislation, which became effective on January 1, 2018, decreased the U.S. corporate federal income tax rate from 35% to 21%. The TCJA also included a number of provisions, including the elimination of loss carrybacks and limitations on the use of future losses, repeal of the Alternative Minimum Tax regime, the limitation on the deductibility of certain expenses, including interest expense, and changes in the way that capital costs are recovered.

Given the significant complexity of the TCJA and anticipated additional implementation guidance from the Internal Revenue Service, further implications of TCJA may be identified in future periods.  Amounts recorded in the condensed consolidated financial statements are provisional.

7.  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. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.  The prices we receive for our production depend on many factors outside of our 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 in the Company’s forward cash flows supporting the Company’s capital investment program.  These types of instruments may include fixed price swaps, costless collars, or basis differential swaps.  These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

The Company’s hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval. During the three and nine months ended September 30, 2018, the Board approved all commodity derivative hedge contracts for volumes exceeding 50% of forecasted production volumes.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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Fair Value of Commodity Derivatives:  FASB ASC 815 requires that all derivatives be recognized on the Condensed Consolidated Balance Sheets as either an asset or liability and 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 Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Condensed Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments.

Commodity Derivative Contracts:  At September 30, 2018, the Company had the following open commodity derivative contracts to manage commodity price risks.  For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty.  For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period.  The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

 

 

Subsequent to September 30, 2018 and through October 25, 2018, the Company entered into the following open commodity derivative contracts to manage commodity price risk.

 

 

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three and six months ended September 30, 2018 and 2017:

 

 

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 derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

 

8.  FAIR VALUE MEASUREMENTS:

As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

 

 

The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk.  Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract.  In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties.  In addition, each of our current counterparties are lenders under our Revolving Credit Facility.  We believe that

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

all of our counterparties are of substantial credit quality.  Other than as provided in our Revolving Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us.  As of September 30, 2018, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts.

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs.  This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s consolidated financial position, results of operations or cash flows.

 

 

9.  COMMITMENTS AND CONTINGENCIES:

The Plan (defined below) provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Quarterly Report on Form 10-Q, the claims resolution process associated with our chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time.

Pending Claims – Ultra Resources Indebtedness

Our chapter 11 filings as described in Note 10 constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court (as defined in Note 10), asserting various claims against us, including claims for unpaid postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. We disputed the claims made by the holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the prepetition debt agreements. As previously disclosed, on September 22, 2017, the Bankruptcy Court denied our objection to the pending make-whole and postpetition interest claims.  Further, on October 6, 2017, the Bankruptcy Court entered an order requiring us to distribute amounts attributable to the disputed claims to the applicable parties.  Pursuant to the order, on October 12, 2017, we distributed $399.0 million from a $400.0 million reserve fund set up in connection with our emergence from chapter 11 proceedings to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company.  The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate.  The Company is appealing the court order denying its objections to these claims, but it is not possible to determine the ultimate disposition of these matters at this time.

Royalties

On April 19, 2016, the Company received a preliminary determination notice from the U.S. Department of the Interior’s Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under federal oil and gas leases.  ONRR also filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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million in claims related to these matters.  We dispute the preliminary determination and the proof of claim.  We have notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice, and we continue to be in discussions with ONRR related to these matters. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods.  The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

Oil Sales Contract

On April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed 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 on December 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of contract by SPMT during the prepetition period (as amended, the “Sunoco Adversary”).  In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters 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.  At September 30, 2018, the Company accrued the payment of $2.0 million and wrote off the related receivable of approximately $0.7 million.

Other Claims

We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, and we cannot reasonably estimate the potential impact of these claims. We are defending all these claims vigorously, and we expect these claims to be resolved in our chapter 11 proceedings. In addition, we are currently involved in various routine disputes and allegations incidental to our business operations. While it is not possible to determine the ultimate disposition of these matters, we believe the resolution of all such routine disputes and allegations is not likely to have a material adverse effect on our financial position or results of operations.

10.  CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.).

On February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), on March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”), and on April 12, 2017 (the “Effective Date”), we emerged from bankruptcy.

Plan of Reorganization

Pursuant to the Plan, the significant transactions that occurred upon our emergence from chapter 11 proceedings were as follows:

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ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Fresh Start Accounting

As previously disclosed, we were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims.

Bankruptcy Claims Resolution Process

The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims are 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 bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed.

Costs of Reorganization

During 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

The following table summarizes the components included in Reorganization items, net in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017:

 

 

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

11.  SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2018 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below:

For each $1,000 aggregate principal amount of 2022 Notes validly exchanged pursuant to the Exchange Agreement, the Supporting Noteholders will receive (i) $720 aggregate principal amount of New Notes issued by Ultra Resources and (ii) 14.0 Warrants issued by the Company; and, for each $1,000 aggregate principal amount of 2025 Notes validly exchanged pursuant to the Exchange Agreement, the Supporting Noteholders will receive (i) $660 aggregate principal amount of New Notes issued by Ultra Resources and (ii) 14.0 Warrants issued by the Company.

Each Warrant will be exercisable at the option of the holders thereof for one common share of the Company, at any time following the date on which the volume-weighted average price of the common shares is at least $2.50 for 30 consecutive trading days. In the aggregate, if all Warrants are exercised, total shareholder dilution will be approximately 6%.

The obligations of the Supporting Noteholders under the Exchange Agreement, including their obligation to exchange their 2022 Notes and 2025 Notes pursuant to the exchange transaction, are subject to the conditions set forth in the Exchange Agreement, including: (a) the Company receiving a consent of the requisite lenders under the Credit Agreement to the consummation of the transactions contemplated by the Exchange Agreement; (b) the Company receiving a consent of the requisite lenders under the Term Loan Agreement to the consummation of the transactions contemplated by the Exchange Agreement; (c) entry into a customary intercreditor agreement between the agent for the Credit Agreement, the agent for the Term Loan Agreement and trustee collateral agent for the New Notes; and (d) the execution and delivery of an indenture pursuant to which the New Notes will be governed and other definitive documentation. Accordingly, there can be no assurance if or when the Company will consummate the exchange transaction and the other transactions contemplated by the Exchange Agreement.

The Exchange Agreement may be terminated by the Company, on the one hand, or the Supporting Noteholders owning at least a majority in aggregate principal amount of each series of the 2022 Notes and the 2025 Notes, on the other hand, on behalf of the Supporting Noteholders, upon written notice of termination to the other parties, if the closing of the exchange transaction has not occurred on or before November 15, 2018 or by any single Supporting Noteholder, solely with respect to itself, if the closing of the exchange transaction has not occurred on or before December 15, 2018.

 

 

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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the Company’s condensed consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

Overview

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, “us”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

Substantially all of the Company’s oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies.  Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with a portion of the Company’s revenues coming from oil sales from its properties in the Uinta Basin in Utah.

On September 25, 2018, the Company completed the sale of its Utah assets to an unnamed third party for net cash proceeds of $69.3 million, including management fees of $0.6 million. The divested assets consisted primarily of oil and gas properties.

DESCRIPTION OF THE BUSINESS:

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 this volatility could be detrimental to the Company’s financial performance.  As a result, from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas and oil. See Note 7 for additional details.

During the quarter ended September 30, 2018, the average price realization for the Company’s natural gas was $2.38 per Mcf, including realized gains and losses on commodity derivatives, compared with $2.87 per Mcf during the quarter ended September 30, 2017.  The Company’s average price realization for natural gas was $2.46 per Mcf, excluding the realized gains and losses on commodity derivatives during the quarter ended September 30, 2018, as compared with $2.74 per Mcf during the quarter ended September 30, 2017.

During the quarter ended September 30, 2018, the average price realization for the Company’s oil was $58.02 per barrel, including realized gains and losses on commodity derivatives, compared to $45.86 per barrel during the quarter ended September 30, 2017.  The Company’s average price realization for oil was $66.54 per barrel, excluding the realized gains and losses on commodity derivatives during the quarter ended September 30, 2018, as compared with $45.86 per barrel during the quarter ended September 30, 2017.

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2017 Chapter 11 Proceedings

As discussed in Note 10, the Company emerged from chapter 11 proceedings during the year ended December 31, 2017.  The effects of the Plan (defined below) were included in the Consolidated Financial Statements as of December 31, 2017 and the related adjustments thereto were recorded in our Condensed Consolidated Statement of Operations as reorganization items for the quarter and nine months ended September 30, 2018.

Voluntary Reorganization Under Chapter 11

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.).

On February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), on March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”), and on April 12, 2017 (the “Effective Date”), we emerged from bankruptcy. See Note 10 for additional details.

Plan of Reorganization

Pursuant to the Plan:

Fresh Start Accounting

As previously disclosed, we were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims. 

Bankruptcy Claims Resolution Process

The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims 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 bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed.

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Costs of Reorganization

During 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

The following table summarizes the components included in Reorganization items, net in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017:

 

 

Critical Accounting Policies

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments.

Derivative Instruments and Hedging Activities.  The Company follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”).  The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements.  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 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 market participants at measurement date and establishes a three-level hierarchy for measuring fair value.

 

 

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 Environmental Obligations (“FASB ASC 410”) requires that the fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates,

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assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through depletion, depreciation and amortization (“DD&A”).  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 Condensed Consolidated Balance Sheets.

Share-Based Payment Arrangements.  The Company applies 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, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2018 and 2017 was $11.5 million and $34.2 million, respectively. See Note 5 for additional details.

Property, Plant and Equipment.  Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

Full Cost Method of Accounting.  The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and FASB ASC Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test 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 performed quarterly, 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 in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future 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-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower 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 calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2018 or 2017.  

Revenue Recognition.  The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. During the nine months ended September 30, 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’s adoption of this standard.

Valuation of Deferred Tax Assets.  The Company uses the asset and liability method of accounting for income taxes. Under this method, future income 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 tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management

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considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

During the year ended December 31, 2017, the Company recorded an expected benefit for the recovery of the Company’s carryforward Alternative Minimum Tax (“AMT”) credits.  During the nine months ended September 30, 2018, the Company recorded income tax expense of approximately $0.4 million related to the Internal Revenue Service effect of a 6.6% sequestration rate on the expected AMT credit.

The Company has recorded a valuation allowance against all of its deferred tax assets as of September 30, 2018.  Some or all of this valuation allowance may be reversed in future periods against future income. On December 22, 2017, the Tax Cuts and Jobs Act (“TCJA”) was enacted into law.  The legislation, which became effective on January 1, 2018, decreased the U.S. corporate federal income tax rate from 35% to 21%.  The TCJA also included a number of provisions, including the elimination of loss carrybacks and limitations on the use of future losses, repeal of the AMT regime, the limitation on the deductibility of certain expenses, including interest expense, and changes in the way that capital costs are recovered.

Deferred Financing Costs.  The Company follows ASU No. 2015-3, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, and includes the costs for issuing debt, including issuance discounts, except those related to the Revolving Credit Facility, as a direct deduction from the carrying amount of the related debt liability. Costs related to the issuance of the Revolving Credit Facility are recorded as an asset in the Condensed Consolidated Balance Sheets.

Conversion of Barrels of Oil to Mcfe of Gas.  The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil 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 barrel of oil or other liquids to an Mcf of natural gas.  The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas 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 Bbl of oil or other liquids.

Recent accounting pronouncements:

Leases.  In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”).  The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information.   For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements. To facilitate compliance with ASC 842, the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, initiated the process of reviewing its contract portfolio, and implemented appropriate changes to business systems. The Company will continue to evaluate its processes and internal controls during 2018. Additionally, we are evaluating the disclosure requirements under the new standard to ensure the appropriate information will be available for these disclosures.  While we are continuing to assess all potential impacts of the standard, we anticipate recognition of additional assets and corresponding liabilities related to leases. The overall financial impact is continuing to be evaluated by the Company.

Stock Compensation.  In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) (“ASU No. 2017-09”), which is intended 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 of this ASU did not have a material impact on the Company’s consolidated financial statements.

Derivatives.  In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815) (“ASU No. 2017-12”), which makes significant changes 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 periods beginning after December 15, 2018, including interim periods within those annual periods.  The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements.

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

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modify the disclosure requirements on fair value measurements 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.

Revenue from Contracts with Customers.  In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers 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”) to all contracts entered into in 2017 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 Topic 606, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances.  The impact to revenues for the nine months ended September 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606.  The comparative information has not been restated and continues to be reported under the accounting standards for those periods.  See Note 2 for further details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

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CONSOLIDATED RESULTS OF OPERATIONS:

The following table summarizes our unaudited condensed consolidated statement of operations for the periods indicated:

 

 

Quarter Ended September 30, 2018 vs. Quarter Ended September 30, 2017

Production, Commodity Derivatives and Revenues:

Production.  During the quarter ended September 30, 2018, total production decreased on a gas equivalent basis to 67.5 Bcfe compared to 71.1 Bcfe for the same period in 2017. The decrease is primarily attributable to a decrease in capital investment and development activity, and a decrease in production due to the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017 and the assets in Utah during the third quarter of 2018.

Commodity Prices – Natural Gas.  During the quarter ended September 30, 2018, realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 17% to $2.38 per Mcf as compared to $2.87 per Mcf for the same period in 2017.  The Company has entered into various natural gas price commodity derivative contracts with contract periods

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extending through the first quarter of 2020. See Note 7 for additional details.  During the quarter ended September 30, 2018, the Company’s average price, excluding realized gains and losses on commodity derivatives, for natural gas was $2.46 per Mcf as compared to $2.74 per Mcf for the same period in 2017.

Commodity Prices – Oil.  During the quarter ended September 30, 2018, the average price realization for the Company’s oil, including realized gains and losses on commodity derivatives, increased to $58.02 per barrel as compared to $45.86 per barrel for the same period in 2017. The Company has entered into various oil price commodity derivative contracts with contract periods extending through 2020. See Note 7 for additional details. During the three months ended September 30, 2018, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $66.54 per barrel as compared to $45.86 per barrel for the same period in 2017.

Revenues.  During the quarter ended September 30, 2018, revenues decreased to $203.8 million as compared to $217.6 million for the same period in 2017.  This decrease is primarily attributable to the decrease in average natural gas prices and total production, partially offset by the increase in average oil prices.

Operating Costs and Expenses:

Lease Operating Expense.  Lease operating expense (“LOE”) increased to $25.8 million during the quarter ended September 30, 2018 as compared to $23.1 million during the same period in 2017 due mainly to a higher well count in Wyoming resulting from the Company’s drilling program. On a unit of production basis, LOE costs increased to $0.38 per Mcfe during the quarter ended September 30, 2018 as compared with $0.33 per Mcfe during the same period in 2017, due to higher absolute costs and decreased total production during the period ended September 30, 2018.

Facility Lease Expense.  During December 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual base rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which base rent may increase if certain volume thresholds are exceeded. We expect to incur additional rent expense in 2018 due to exceeding volume thresholds. The lease is classified as an operating lease. For the quarter ended September 30, 2018, the Company recognized operating lease expense associated with the Lease Agreement of $6.9 million, or $0.10 per Mcfe, as compared to $5.3 million, or $0.07 per Mcfe for the same period in 2017.

Production Taxes.  During the quarter ended September 30, 2018, production taxes decreased to $20.5 million compared to $22.5 million during the same period in 2017, or $0.30 per Mcfe compared to $0.32 per Mcfe, respectively. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 10.0% of revenues for the quarter ended September 30, 2018 and 10.3% of revenues for the same period in 2017.  The decrease in per unit taxes was primarily attributable to decreased natural gas prices during the quarter ended September 30, 2018 as compared to the same period in 2017.

Gathering Fees.  During the quarter ended September 30, 2018, gathering fees decreased to $21.8 million compared to $22.2 million during the same period in 2017, related to decreased production volumes.  On a per unit basis, gathering fees increased to $0.32 per Mcfe for the quarter ended September 30, 2018 compared with $0.31 per Mcfe for the same period in 2017.

Depletion, Depreciation and Amortization.  During the quarter ended September 30, 2018, DD&A expense increased to $49.7 million compared to $41.1 million for the same period in 2017.  The increase is primarily attributable to a higher depletion rate due to a higher depletable base from the increase in capital expenditures as part of the Company’s drilling program and the recognition of proved undeveloped properties, offset by decreased production volumes during the quarter ended September 30, 2018.  On a unit of production basis, the DD&A rate increased to $0.74 per Mcfe for the quarter ended September 30, 2018 compared to $0.58 per Mcfe for the same period in 2017.

General and Administrative Expenses. During the quarter ended September 30, 2018, general and administrative expenses decreased to $1.5 million as compared to $8.2 million for the same period in 2017. The decrease is primarily attributable to the $7.9 million of non-cash stock incentive compensation expense that was incurred during the quarter ended September 30, 2017 as part of the Management Incentive Plan. See Note 5 for additional details.  On a per unit basis, general and administrative expenses decreased to $0.02 per Mcfe for the quarter ended September 30, 2018 compared to $0.12 per Mcfe for the same period in 2017.

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Other Income and Expenses:

Interest Expense.  During the quarter ended September 30, 2018, interest expense of $38.4 million decreased as compared to $210.1 million during the same period in 2017.  The decrease is primarily attributable to the postpetition interest of $175.2 million recognized in the quarter ending September 30, 2017, related to the Bankruptcy Court order denying our objection to postpetition interest claims. See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Unsecured Notes.

Contract Settlement Expense.  During the quarter ended September 30, 2018, the Company incurred $2.7 million in expense related to the Sunoco Partners Marketing & Terminals L.P. (“SPMT”) settlement.  SPMT filed a claim in 2016 against the Company in regard to an alleged breach of contract, and the Company reached a settlement in October 2018.  There were no material contract settlement expenses for the same period in 2017. See Note 9 for additional details regarding the SPMT settlement.

Deferred Gain on Sale of Liquids Gathering System (“LGS”).  During the quarters ended September 30, 2018 and 2017, the Company recognized $2.6 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

(Loss) Gain on Commodity Derivatives. During the quarter ended September 30, 2018, the Company recognized a loss of $21.8 million, as compared to a gain of $4.7 million related to commodity derivatives for the same period in 2017. Of this total, the Company recognized $10.8 million related to a realized loss on commodity derivatives during the quarter ended September 30, 2018 compared with $8.9 million related to a realized gain on commodity derivatives during the same period in 2017. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This amount also includes an unrealized loss of $11.0 million on commodity derivatives during the quarter ended September 30, 2018, as compared to an unrealized loss of $4.2 million during the same period in 2017. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.  See Note 7 for additional details.

Reorganization Items:

Reorganization Items, Net. Reorganization items, net was $227.1 million during the quarter ended September 30, 2017.  The $227.1 million incurred represents $3.3 million of professional fees incurred related to the Company’s chapter 11 proceedings and $223.8 million related to the Bankruptcy Court order denying our objection to the make-whole claims as further described in Note 10.

Income (Loss) from Operations:

Pretax Income (Loss).  During the quarter ended September 30, 2018, the Company recognized income before income taxes of $18.6 million compared to loss before income taxes of $334.6 million for the same period in 2017. The increase in earnings is largely attributable to the reorganization items related to the Bankruptcy Court order denying our objection to the make-whole recognized in the third quarter of 2017 related to the Company’s emergence from chapter 11 proceedings.  See Note 10 for additional details.

Income Taxes.   The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2018.  Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income.  During the quarter ended September 30, 2018, the Company recognized net income of $18.6 million, or $0.09 per diluted share, as compared to net loss of $327.7 million, or $1.67 per diluted share, for the same period in 2017. The increase in earnings is largely attributable to the reorganization items related to the Bankruptcy Court order denying our objection to the make-whole recognized in the third quarter of 2017 related to the Company’s emergence from chapter 11 proceedings.  See Note 10 for additional details.

Nine Months Ended September 30, 2018 vs. Nine Months Ended September 30, 2017

Production, Commodity Derivatives and Revenues:

Production.  During the nine months ended September 30, 2018, total production increased by 4% on a gas equivalent basis to 210.7 Bcfe compared to 202.2 Bcfe for the same period in 2017, primarily attributable to an increase in capital

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investment and development activity and partially offset by the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017 and the assets in Utah during the third quarter of 2018.

Commodity Prices – Natural Gas.  Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 17% to $2.45 per Mcf during the nine months ended September 30, 2018 as compared to $2.95 per Mcf for the same period in 2017.  During the nine months ended September 30, 2018, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through 2020. See Note 7 for additional details. During the nine months ended September 30, 2018, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.41 per Mcf as compared to $2.91 per Mcf for the same period in 2017.

Commodity Prices – Oil.  Realized oil prices, including realized gains and losses on commodity derivatives, increased to $58.89 per barrel during the nine months ended September 30, 2018 as compared to $46.21 per barrel for the same period in 2017.  During the nine months ended September 30, 2018, the Company entered into additional oil price commodity derivative contracts with contract periods extending through the first quarter of 2020.  See Note 7 for additional details.  During the nine months ended September 30, 2018, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was $63.98 per barrel as compared to $46.21 per barrel for the same period in 2017.  

Revenues.  Decreased average natural gas prices, partially offset by increased production and average oil prices, resulted in revenues decreasing to $619.3 million for the nine months ended September 30, 2018 as compared to $651.2 million for the same period in 2017.

Operating Costs and Expenses:

Lease Operating Expense.  LOE increased to $71.2 million during the nine months ended September 30, 2018 compared to $69.4 million during the same period in 2017. On a unit of production basis, LOE costs remained flat at $0.34 per Mcfe during the nine months ended September 30, 2018 and 2017.

Facility Lease Expense.  During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming and the Company entered into the Lease Agreement. The Lease Agreement provides for an initial term of 15 years, and annual base rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which base rent may increase if certain volume thresholds are exceeded. We expect to incur additional rent expense in 2018 due to exceeding volume thresholds. The lease is classified as an operating lease. For the nine months ended September 30, 2018, the Company recognized operating lease expense associated with the Lease Agreement of $19.6 million, or $0.09 per Mcfe, as compared to $15.7 million, or $0.08 per Mcfe, for the same period in 2017.

Production Taxes.  During the nine months ended September 30, 2018, production taxes were $62.6 million compared to $66.4 million during the same period in 2017, or $0.30 per Mcfe compared to $0.33 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 10.1% of revenues for the nine months ended September 30, 2018 and 10.2% of revenues for the same period in 2017.  The decrease in per unit taxes is primarily attributable to decreased natural gas prices during the nine months ended September 30, 2018 as compared to the same period in 2017.

Gathering Fees.  Gathering fees increased to $69.0 million for the nine months ended September 30, 2018 compared to $63.8 million during the same period in 2017, largely related to increased production.  On a per unit basis, gathering fees increased slightly to $0.33 per Mcfe for the nine months ended September 30, 2018 compared to $0.32 per Mcfe for the same period in 2017.

Depletion, Depreciation and Amortization.  DD&A expenses increased to $152.0 million during the nine months ended September 30, 2018 from $111.5 million for the same period in 2017, primarily attributable to a higher depletion rate due to a higher depletable base from the increase in capital expenditures as part of the Company’s drilling program and the recognition of proved undeveloped properties for the nine months ended September 30, 2018 as compared to the same period in 2017. On a unit of production basis, the DD&A rate increased to $0.72 per Mcfe for the nine months ended September 30, 2018 compared to $0.55 per Mcfe for the nine months ended September 30, 2017.

General and Administrative Expenses. General and administrative expenses decreased to $16.2 million for the nine months ended September 30, 2018 compared to $34.3 million for the same period in 2017. The decrease is primarily attributable to the $34.2 million of non-cash stock incentive compensation expense that was incurred during the nine months ended September 30, 2017 as part of the Management Incentive Plan. See Note 5 for additional details. On a per unit basis, general and administrative

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expenses decreased to $0.08 per Mcfe for the nine months ended September 30, 2018 compared to $0.17 per Mcfe for the nine months ended September 30, 2017.

Other Income and Expenses:

Interest Expense.  Interest expense decreased to $111.9 million during the nine months ended September 30, 2018 compared to $325.0 million during the same period in 2017. The decrease in interest expense is primarily attributable to recurring interest expense on the Revolving Credit Facility, Term Loan Agreement, and the Unsecured Notes incurred during the nine months ended September 30, 2018, as compared to the non-recurring accrued postpetition interest, related to the Bankruptcy Court order denying our objection to postpetition interest claims.  See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Unsecured Notes, and see Note 10 for additional details related to our chapter 11 proceedings.

Contract Settlement Expense.  During the nine months ended September 30, 2018, the Company incurred $2.7 million in expense related to the SPMT settlement.  SPMT filed a claim in 2016 against the Company in regard to an alleged breach of contract, and the Company reached a settlement in October 2018.  During the nine months ended September 30, 2017, the Company incurred $52.7 million in expense related to the Sempra Rockies Marketing, LLC (“Sempra”) settlement.  Sempra filed a claim in 2016 against the Company in regard to an alleged breach of contract, and the Company reached a settlement in April 2017.  See Note 9 for additional details regarding the SPMT settlement.

Deferred Gain on Sale of Liquids Gathering System.  During the nine months ended September 30, 2018 and 2017, the Company recognized $7.9 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

(Loss) Gain on Commodity Derivatives. During the nine months ended September 30, 2018, the Company recognized a loss of $75.6 million related to commodity derivatives as compared to a gain of $12.1 million related to commodity derivatives during the same period in 2017. Of this total, the Company recognized $3.1 million related to realized loss on commodity derivatives during the nine months ended September 30, 2018 as compared with $8.0 million related to a realized gain on commodity derivatives during the same period in 2017. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain or loss on commodity derivatives also includes a $72.6 million unrealized loss on commodity derivatives for the nine months ended September 30, 2018 as compared to a $4.1 million unrealized gain on commodity derivatives for the same period in 2017. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.  See Note 7 for additional details.

Reorganization Items:

Reorganization Items, Net. Reorganization items, net was $142.1 million for the nine months ended September 30, 2017. The $142.1 million is primarily comprised of expenses of $65.2 million in professional fees, settlements, and interest income associated with the Company’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 the gain of $431.1 million, which primarily represents the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes.  See Note 10 for additional details.

Income from Operations:

Pretax Income.  The Company recognized income before income taxes of $45.9 million for the nine months ended September 30, 2018 compared to $74.7 million for the same period in 2017. The decrease in earnings is primarily attributable to the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes recognized during the nine months ended September 30, 2017 as part of the Company’s emergence from chapter 11 proceedings.  See Note 10 for additional details.

Income Taxes.  The Company recorded a $0.4 million tax expense for the nine months ended September 30, 2018 related to the revised sequestration rate of 6.6% on the expected AMT credit. The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 2018.  Some or all of this valuation allowance may be reversed in future periods against future income.

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At December 31, 2017, the Company had approximately $2.1 billion of U.S. federal tax net operating loss carryforwards that expire at various dates from 2033 through 2037 and approximately $102.2 million of Utah state tax net operating loss carryforwards that expire at various dates from 2033 through 2037.

Given the significant complexity of the TCJA and anticipated additional implementation guidance from the Internal Revenue Service, further implications of TCJA may be identified in future periods.  Amounts recorded in the consolidated financial statements are provisional.

Net Income.  For the nine months ended September 30, 2018, the Company recognized net income of $45.5 million, or $0.23 per diluted share, as compared to $81.6 million, or $0.53 per diluted share, for the same period in 2017. The decrease in earnings is primarily attributable to the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes recognized during the nine months ended September 30, 2017 as part of the Company’s emergence from chapter 11 proceedings.  See Note 10 for additional details.

LIQUIDITY AND CAPITAL RESOURCES

During the nine months ended September 30, 2018, we funded our operations primarily through cash flows from operating activities and borrowings under the Revolving Credit Facility (defined below).  At September 30, 2018, the Company reported a cash position of $13.1 million. At September 30, 2018, the Company had no outstanding borrowings and $325.0 million of available borrowing capacity under the Revolving Credit Facility.

Given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, the Company’s liquidity needs could be significantly higher than the Company currently anticipates.  The Company’s ability to maintain adequate liquidity depends on the prevailing market prices for oil and natural gas, the successful operation of the business, and appropriate management of operating expenses and capital spending.  The Company’s anticipated liquidity needs are highly sensitive to changes in each of these and other factors.  

Capital Expenditures. For the nine month period ended September 30, 2018, total capital expenditures were $339.9 million. During this period, the Company participated in 101 gross (73.4 net) wells in Wyoming that were drilled to total depth and cased.  The wells drilled to total depth and cased included 82 gross (59.0 net) vertical wells and 19 gross (14.4 net) horizontal wells. In September 2018, the Company divested all of its Utah assets and as such, no expenditures will be incurred for this property going forward.

2018 Capital Investment Plan. For 2018, our capital expenditures are expected to be $400.0 million to $415.0 million. We expect to fund these capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility (defined below), the proceeds of the sale of our Utah assets, and cash on hand. We expect to allocate nearly all of our capital investments to development activities in our Pinedale field in Wyoming.

Ultra Resources, Inc.

Credit Agreement. In April 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Agreement (defined below)).  In September 2017, the administrative agent and the other lenders approved an increase in the borrowing base under the Revolving Credit Facility from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the Revolving Credit Facility to an aggregate amount of $425.0 million.  In April 2018, the administrative agent and the other lenders reaffirmed the borrowing base at $1.4 billion.  In September 2018, the borrowing base was reduced to $1.3 billion in connection with the semi-annual redetermination. At September 30, 2018, Ultra Resources had no outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million and a borrowing base of $1.3 billion.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions, and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank 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 to 250 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 any fiscal quarter, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise

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apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00.  The Revolving Credit Facility loans mature on January 12, 2022.

The Revolving Credit Facility requires Ultra Resources 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 consolidated net leverage ratio that does not exceed (a) 4.50 to 1.00, during the period ending on the last day of the fiscal quarter ending June 30, 2019, (b) 4.25 to 1.00, during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ending on the last day of the fiscal quarter ending December 31, 2019, and (c) 4.00 to 1.00 beginning on the last day of the fiscal quarter ending on March 31, 2020; and (iv) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.

Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, the Company 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 the quarterly projected volumes of natural gas from PDP reserves.  Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement. The Company expects to be in compliance with these requirements while the requirements remain effective.  

Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing 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 comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated.

Term Loan. In April 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million 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 drawn immediately after the funding of the initial term loan.  In September 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under the Term Loan Agreement to $975.0 million.  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 noted in the table above.  The Term Loan Agreement has capacity to increase the commitments subject to certain conditions.  At September 30, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement, including current maturities.

The Term Loan Agreement bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points.  The Term Loan Agreement amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Agreement matures on April 12, 2024.

The Term Loan Agreement is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the 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 Loan Agreement.

The Term Loan Agreement also contains customary affirmative and negative covenants, including 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

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incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Senior Unsecured Notes. In April 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, and the Company and its subsidiaries, as guarantors. The Unsecured Notes are treated as a single class of securities under the Indenture.

The Unsecured Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Unsecured Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act.

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 Notes will 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 Unsecured Notes from the issue date until maturity.

Prior to April 15, 2019, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2022 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

If Ultra Resources experiences certain change of control triggering events as set forth in the Indenture, each holder of the Unsecured Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Unsecured Notes, plus any accrued but unpaid interest to the date of repurchase.

The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Unsecured Notes receive investment grade

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ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Unsecured Notes.

The Indenture contains customary events of default. Unless otherwise noted in the Indenture, upon a continuing event of default, the trustee under the Indenture (the “Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable.

On October 17, 2018, the Company entered into an exchange agreement relating to the Unsecured Notes, as discussed further in Note 11.

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

Cash flows provided by (used in):

Operating Activities.  During the nine months ended September 30, 2018, net cash provided by operating activities was $314.7 million compared to $148.8 million for the same period in 2017. The increase in net cash provided by operating activities is largely attributable to the timing of nonrecurring expenses related to the Company’s reorganization under chapter 11 proceedings in 2017 and partially offset by the decrease in natural gas prices.

Investing Activities.  During the nine months ended September 30, 2018, net cash used in investing activities was $315.1 million as compared to $374.0 million for the same period in 2017. The decrease in net cash used in investing activities is largely related to increased capital investments associated with the Company’s drilling activities during the nine months ended September 30, 2017, partially offset by the proceeds from the sale of the Utah assets in September 2018.

Financing Activities.  During the nine months ended September 30, 2018, net cash used in financing activities was $2.7 million as compared to net cash provided by financing activities of $227.3 million for the same period in 2017. The change in net cash used in financing activities is primarily due to the restructuring of debt and equity as part of the Company’s emergence from chapter 11 proceedings during the nine months ended September 30, 2017.  See Note 10 for additional details.  

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2018.

CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding the Company’s financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and 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 such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the Company assure adequate funding will be available to execute the Company’s planned future capital program.

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and

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increased financing costs due to a significant increase in interest rates. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 for additional risks related to the Company’s business.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Objectives and Strategy:  The Company is exposed to commodity price risk.  The following quantitative and qualitative information is provided about financial instruments to which we were a party at September 30, 2018, and from which we may incur future gains or losses from changes in commodity prices.  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 driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.  The prices we receive for our production depend on many factors outside of our 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 in the Company’s forward cash flows supporting the Company’s capital investment program.  These types of instruments may include fixed price swaps, costless collars, or basis differential swaps.  These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

The Company’s hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval. During the quarter and nine months ended September 30, 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 Consolidated Balance Sheets as either an asset or liability and 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 Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.  See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts:  At September 30, 2018, the Company had the following open commodity derivative contracts to manage commodity price risk.  For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty.  For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period.  The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

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⁽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 last trading day of the month by the NYMEX for natural gas swaps for the respective period.

 

Subsequent to September 30, 2018 and through October 25, 2018, the Company entered into the following open commodity derivative contracts to manage commodity price risk.

 

 

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017: 

 

 

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 derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

ITEM 4 — CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has performed an evaluation under the supervision and with the participation of our management, including our Interim Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report on Form 10-Q. The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to

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ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Interim Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Interim Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Other Claims:    See Note 9 for additional discussion of on-going claims and disputes in our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

ITEM 1A.  RISK FACTORS

Our business has many risks.  Any of the risks discussed in this Quarterly Report on Form 10-Q or in our other SEC filings, could have a material impact on our business, financial position, or results of operations.  Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.  There have been no material changes to the risks described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

None.

ITEM 5.  OTHER INFORMATION

Appointment of Chief Financial Officer

On November 5, 2018, the Board appointed Mr. David Honeyfield as Chief Financial Officer of the Company, effective November 9, 2018.  Mr. Honeyfield, age 51, most recently served as Senior Vice President and Chief Financial Officer of PDC Energy, Inc. from December 2016 to January 2018, and as Chief Financial Officer of Jonah Energy LLC from August 2014 to December 2016. Also, his previous experience includes six years at Intrepid Potash, Inc., including most recently as President and Chief Financial Officer. Prior to that, he served in various leadership roles including Senior Vice President and Chief Financial Officer of SM Energy, and Controller and Chief Accounting Officer of Cimarex Energy Co.  Prior to that, Mr. Honeyfield was a Senior Audit Manager with Arthur Andersen LLP in Denver, where he focused on clients in the oil and gas exploration and production, manufacturing and mining sectors. Mr. Honeyfield holds a Bachelor of Arts degree in economics from the University of Colorado and is a Certified Public Accountant.

Mr. Honeyfield was not appointed pursuant to any arrangement or understanding with any other person, and there are no transactions with Mr. Honeyfield that would be reportable under Item 404(a) of Regulation S-K.

Employment Agreement

On November 7, 2018, the Company entered into an employment agreement with Mr. Honeyfield (the “Employment Agreement”).  The Employment Agreement provides Mr. Honeyfield with an initial base salary of $500,000 per year; an aggregate sign-on bonus of $100,000 payable in two equal installments (the “Sign-On Bonus”); eligibility to receive cash-based incentive compensation pursuant to the Company’s short-term incentive programs as in effect from time to time with a target amount equal to 90% of his annual base salary; and eligibility to receive grants of equity-based incentive compensation in the form of restricted stock units and performance based restricted stock units.  The Employment Agreement also provides Mr. Honeyfield with other benefits, including health insurance and the opportunity to participate in a 401(k) plan, to the same extent as such benefits are available to the Company’s other salaried employees.

The Employment Agreement provides that either the Company or Mr. Honeyfield can terminate his employment relationship. The Company’s right to terminate the employment relationship is subject to its obligation to make certain severance

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payments and provide certain other benefits to Mr. Honeyfield, depending upon the circumstances under which the employment relationship is terminated.  The Company is generally not obligated, under the Employment Agreement, to provide any severance payments or benefits if Mr. Honeyfield is terminated for cause or if Mr. Honeyfield resigns without good reason, and the Company is generally obligated, under the Employment Agreement, to provide the severance payments and benefits as set forth in the Employment Agreement if the Company terminates him without cause, or if he resigns with good reason (each, as defined in the Employment Agreement).  In the event Mr. Honeyfield’s employment is terminated by the Company without cause, or in the event Mr. Honeyfield resigns for good reason, the Company will be obligated (subject to Mr. Honeyfield’s timely execution and non-revocation of a release of claims) to provide Mr. Honeyfield with the following severance benefits: (i) payment of any accrued but unpaid compensation as of the termination date, (ii) payment of a prorated portion of Mr. Honeyfield’s annual cash incentive compensation based on the Company’s actual performance at the conclusion of the performance period, (iii) a lump-sum payment equal to Mr. Honeyfield’s then-current annual base salary, and (iv) continued coverage under the Company’s health and welfare benefits programs for the shorter of (x) 12 months following Mr. Honeyfield’s termination and (y) the date on which Mr. Honeyfield is eligible for comparable coverage under a subsequent employer. In addition, Mr. Honeyfield must repay to the Company (i) the full amount of the Sign-On Bonus previously paid to Mr. Honeyfield, if his employment is terminated by the Company for cause, or if he resigns other than for good reason, in each case before November 9, 2019, or (ii) $25,000 of the Sign-On Bonus, if his employment is terminated due to death or disability before November 9, 2019.

The Employment Agreement also contains various other ordinary and customary covenants for the Company’s benefit by Mr. Honeyfield with respect to inventions, non-competition, non-solicitation, non-disparagement, confidentiality, and cooperation and assistance with respect to litigation or other adjudicatory proceedings.

The foregoing description of the Employment Agreement is qualified in its entirety by reference to the full text of the Employment Agreement, which will be filed as an exhibit to the Company’s Annual Report on Form 10-K for the year ending December 31, 2018.

Grant of Restricted Stock Units

In connection with Mr. Honeyfield’s appointment as Chief Financial Officer, the Company will grant, effective November 9, 2018, an aggregate of 613,584 restricted stock units (“RSUs”) to Mr. Honeyfield pursuant to a restricted stock unit grant agreement (the “RSU Grant Agreement”).  The RSU Grant Agreement is subject to the terms and conditions of the A&R Stock Incentive Plan, and generally provides for the following terms:

The foregoing description of the RSU Grant Agreement is qualified in its entirety by reference to the full text of the form of RSU Grant Agreement, of which a copy is attached to this Quarterly Report on Form 10-Q as Exhibit 10.3 and is incorporated herein by reference.

 

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ITEM 6.  EXHIBITS

(a)  Exhibits

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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