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 consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.
Overview
Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company 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.
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 June 30, 2018, the average price realization for the Company’s natural gas was $2.28 per Mcf, including realized gains and losses on commodity derivatives, compared with $2.84 per Mcf during the quarter ended June 30, 2017. The Company’s average price realization for natural gas was $2.11 per Mcf, excluding the realized gains and losses on commodity derivatives during the quarter ended June 30, 2018, as compared with $2.85 per Mcf during the quarter ended June 30, 2017.
During the quarter ended June 30, 2018, the average price realization for the Company’s oil was $58.24 per barrel, including realized gains and losses on commodity derivatives, compared to $45.51 per barrel during the quarter ended June 30, 2017. The Company’s average price realization for oil was $64.71 per barrel, excluding the realized gains and losses on commodity derivatives during the quarter ended June 30, 2018, as compared with $45.51 per barrel during the quarter ended June 30, 2017.
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 Consolidated Statement of Operations as reorganization items for the quarter and six months ended June 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.).
25
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:
|
•
|
On November 21, 2016, we entered into a Plan Support Agreement (as amended, the “PSA”) with certain holders of the Company’s prepetition indebtedness and outstanding common stock as well as a Backstop Commitment Agreement (“BCA”). Pursuant to the BCA, we agreed to conduct a rights offering for new common stock in the Company to be issued upon the effectiveness of the Plan for an aggregate purchase price of $580.0 million (the “Rights Offering”).
|
|
•
|
On February 8, 2017, we entered into a commitment letter with Barclays Bank PLC (“Barclays”) (as amended, the “Commitment Letter”) pursuant to which, in connection with the consummation of the Plan, Barclays agreed to provide us with secured and unsecured financings in an aggregate amount of up to $2.4 billion (the “Debt Financings”).
|
|
•
|
On the Effective Date, the principal obligations outstanding of $999.0 million under the prepetition credit agreement and $1.46 billion under the prepetition senior notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under the prepetition credit agreement and the prepetition senior notes were cancelled and extinguished as provided in the Plan.
|
|
•
|
On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 million related to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full. Each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan.
|
|
•
|
On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.
|
Fresh Start 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.
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.
26
The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the
quarter and six months ended June 30, 2017
:
|
|
For the Quarter Ended
|
|
|
For the Six Months Ended
|
|
|
|
June 30, 2017
|
|
|
June 30, 2017
|
|
Professional fees
|
|
$
|
(4,313
|
)
|
|
$
|
(62,004
|
)
|
Gains (losses) (1)
|
|
|
431,107
|
|
|
|
431,107
|
|
Other (2)
|
|
|
22
|
|
|
|
167
|
|
Total Reorganization items, net
|
|
$
|
426,816
|
|
|
$
|
369,270
|
|
(1)
|
Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 Notes and 2024 Notes.
|
(2)
|
Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.
|
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.
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
—
|
|
|
$
|
14,480
|
|
|
$
|
—
|
|
|
$
|
14,480
|
|
Long-term derivative asset (1)
|
|
|
—
|
|
|
|
3,692
|
|
|
|
—
|
|
|
|
3,692
|
|
Total derivative instruments
|
|
$
|
—
|
|
|
$
|
18,172
|
|
|
$
|
—
|
|
|
$
|
18,172
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
—
|
|
|
$
|
54,891
|
|
|
$
|
—
|
|
|
$
|
54,891
|
|
Long-term derivative liability (2)
|
|
|
—
|
|
|
|
7,853
|
|
|
|
—
|
|
|
|
7,853
|
|
Total derivative instruments
|
|
$
|
—
|
|
|
$
|
62,744
|
|
|
$
|
—
|
|
|
$
|
62,744
|
|
(1)
|
Included in other assets in the Consolidated Balance Sheet.
|
(2)
|
Included in other long-term obligations in the Consolidated Balance Sheet.
|
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, 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,
27
settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obli
gations in the accompanying 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 six months ended June 30, 2018 and 2017 was $10.1 million and $26.3 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 six months ended June 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 six months ended June 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 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 six months ended June 30, 2018, the Company recorded
28
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 June 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 new 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 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
(“ASU No. 2016-02”). 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.
To facilitate compliance with this ASU,
the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, begun the process of reviewing its contract portfolio
and continues to evaluate its systems, processes, and internal controls during 2018.
In January 2018, the FASB issued ASU No. 2018-01,
Land Easement Practical Expedient for Transition to Topic 842
(“ASU No. 2018-01”), which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired before the entity’s adoption of this ASU and that were not previously accounted for as leases. For public companies, the standards 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.
The Company is still evaluating the impact of ASU No. 2016-02 and ASU No. 2018-01 on its consolidated financial statements
.
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.
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.
29
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 $1.8 million as of January 1, 2018 due to the cumulative impact of adopting Topic 606, with the impact related t
o changing from the entitlements method to the sales method to account for wellhead imbalances. The impact to revenues for the six months ended June 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606.
The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for further details related to the adoption of this standard. We expect the impact of the adoption of the new rev
enue standard to be immaterial to our net income on an on-going basis.
RESULTS OF OPERATIONS:
|
|
For the Quarter Ended
|
|
|
|
|
|
|
For the Six Months
|
|
|
|
|
|
|
|
Ended June 30,
|
|
|
%
|
|
|
Ended June 30,
|
|
|
%
|
|
|
|
2018
|
|
|
2017
|
|
|
Variance
|
|
|
2018
|
|
|
2017
|
|
|
Variance
|
|
|
|
(Amounts in thousands, except per unit data)
|
|
Production, Commodity Prices and Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
66,892
|
|
|
|
63,067
|
|
|
|
6
|
%
|
|
|
135,128
|
|
|
|
123,056
|
|
|
|
10
|
%
|
Crude oil and condensate (Bbl)
|
|
|
667
|
|
|
|
675
|
|
|
|
(1
|
)%
|
|
|
1,345
|
|
|
|
1,338
|
|
|
|
1
|
%
|
Total production (Mcfe)
|
|
|
70,894
|
|
|
|
67,118
|
|
|
|
6
|
%
|
|
|
143,198
|
|
|
|
131,084
|
|
|
|
9
|
%
|
Commodity Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($/Mcf, excluding hedges)
|
|
$
|
2.11
|
|
|
$
|
2.85
|
|
|
|
(26
|
)%
|
|
$
|
2.39
|
|
|
$
|
3.00
|
|
|
|
(20
|
)%
|
Natural gas ($/Mcf, including realized hedges)
|
|
$
|
2.28
|
|
|
$
|
2.84
|
|
|
|
(20
|
)%
|
|
$
|
2.48
|
|
|
$
|
2.99
|
|
|
|
(17
|
)%
|
Oil and condensate ($/Bbl, excluding hedges)
|
|
$
|
64.71
|
|
|
$
|
45.51
|
|
|
|
42
|
%
|
|
$
|
62.79
|
|
|
$
|
46.39
|
|
|
|
35
|
%
|
Oil and condensate ($/Bbl, including realized hedges)
|
|
$
|
58.24
|
|
|
$
|
45.51
|
|
|
|
28
|
%
|
|
$
|
59.31
|
|
|
$
|
46.39
|
|
|
|
28
|
%
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
141,255
|
|
|
$
|
179,997
|
|
|
|
(22
|
)%
|
|
$
|
322,716
|
|
|
$
|
368,848
|
|
|
|
(13
|
)%
|
Oil sales
|
|
|
43,167
|
|
|
|
30,732
|
|
|
|
40
|
%
|
|
|
84,451
|
|
|
|
62,081
|
|
|
|
36
|
%
|
Other revenues
|
|
|
5,716
|
|
|
|
1,928
|
|
|
|
196
|
%
|
|
|
8,344
|
|
|
|
2,687
|
|
|
|
211
|
%
|
Total operating revenues
|
|
$
|
190,138
|
|
|
$
|
212,657
|
|
|
|
(11
|
)%
|
|
$
|
415,511
|
|
|
$
|
433,616
|
|
|
|
(4
|
)%
|
Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivatives
|
|
$
|
6,662
|
|
|
$
|
(868
|
)
|
|
|
(868
|
)%
|
|
$
|
7,736
|
|
|
$
|
(868
|
)
|
|
|
(991
|
)%
|
Unrealized gain (loss) on commodity derivatives
|
|
|
(53,933
|
)
|
|
|
21,585
|
|
|
|
(350
|
)%
|
|
|
(61,539
|
)
|
|
|
8,367
|
|
|
|
(835
|
)%
|
Total gain (loss) on commodity derivatives
|
|
$
|
(47,271
|
)
|
|
$
|
20,717
|
|
|
|
(328
|
)%
|
|
$
|
(53,803
|
)
|
|
$
|
7,499
|
|
|
|
(817
|
)%
|
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
23,645
|
|
|
$
|
23,089
|
|
|
|
2
|
%
|
|
$
|
45,409
|
|
|
$
|
46,225
|
|
|
|
(2
|
)%
|
Facility lease expense
|
|
$
|
6,526
|
|
|
$
|
5,226
|
|
|
|
25
|
%
|
|
$
|
12,682
|
|
|
$
|
10,452
|
|
|
|
21
|
%
|
Production taxes
|
|
$
|
18,883
|
|
|
$
|
21,754
|
|
|
|
(13
|
)%
|
|
$
|
42,153
|
|
|
$
|
43,887
|
|
|
|
(4
|
)%
|
Gathering fees
|
|
$
|
24,181
|
|
|
$
|
20,642
|
|
|
|
17
|
%
|
|
$
|
47,238
|
|
|
$
|
41,571
|
|
|
|
14
|
%
|
Depletion, depreciation and amortization
|
|
$
|
51,742
|
|
|
$
|
38,673
|
|
|
|
34
|
%
|
|
$
|
102,282
|
|
|
$
|
70,427
|
|
|
|
45
|
%
|
General and administrative expenses
|
|
$
|
2,063
|
|
|
$
|
25,009
|
|
|
|
(92
|
)%
|
|
$
|
14,752
|
|
|
$
|
26,061
|
|
|
|
(43
|
)%
|
Per Unit Costs and Expenses ($/Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.33
|
|
|
$
|
0.34
|
|
|
|
(3
|
)%
|
|
$
|
0.32
|
|
|
$
|
0.35
|
|
|
|
(9
|
)%
|
Facility lease expense
|
|
$
|
0.09
|
|
|
$
|
0.08
|
|
|
|
13
|
%
|
|
$
|
0.09
|
|
|
$
|
0.08
|
|
|
|
13
|
%
|
Production taxes
|
|
$
|
0.27
|
|
|
$
|
0.32
|
|
|
|
(16
|
)%
|
|
$
|
0.29
|
|
|
$
|
0.33
|
|
|
|
(12
|
)%
|
Gathering fees
|
|
$
|
0.34
|
|
|
$
|
0.31
|
|
|
|
10
|
%
|
|
$
|
0.33
|
|
|
$
|
0.32
|
|
|
|
3
|
%
|
Depletion, depreciation and amortization
|
|
$
|
0.73
|
|
|
$
|
0.58
|
|
|
|
26
|
%
|
|
$
|
0.71
|
|
|
$
|
0.54
|
|
|
|
31
|
%
|
General and administrative expenses
|
|
$
|
0.03
|
|
|
$
|
0.37
|
|
|
|
(92
|
)%
|
|
$
|
0.10
|
|
|
$
|
0.20
|
|
|
|
(50
|
)%
|
30
Quarter Ended June 30, 2018 vs. Quarter Ended June 30, 2017
Production, Commodity Derivatives and Revenues:
Production.
During the quarter ended June 30, 2018, total production increased on a gas equivalent basis to 70.9 Bcfe compared to 67.1 Bcfe for the same period in 2017. The increase is primarily attributable to an increase in capital investment and development activity, partially offset by a decrease in Mcf/day due to the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017.
Commodity Prices – Natural Gas.
During the quarter ended June 30, 2018, realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 20% to $2.28 per Mcf as compared to $2.84 per Mcf for the same period in 2017. The Company has entered into various natural gas price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details. During the quarter ended June 30, 2018, the Company’s average price, excluding realized gains and losses on commodity derivatives, for natural gas was $2.11 per Mcf as compared to $2.85 per Mcf for the same period in 2017.
Commodity Prices – Oil.
During the quarter ended June 30, 2018, the average price realization for the Company’s oil, including realized gains and losses on commodity derivatives, increased to $58.24 per barrel as compared to $45.51 per barrel for the same period in 2017. The Company has entered into various oil price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details During the quarter ended June 30, 2018, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $64.71 per barrel as compared to $45.51 per barrel for the same period in 2017.
Revenues.
During the quarter ended June 30, 2018, revenues decreased to $190.1 million as compared to $212.7 million for the same period in 2017. This decrease is primarily attributable to the decrease in average natural gas prices and partially offset by the increase in total production and average oil prices.
Operating Costs and Expenses:
Lease Operating Expense.
Lease operating expense (“LOE”) increased slightly to $23.6 million during the quarter ended June 30, 2018 as compared to $23.1 million during the same period in 2017. On a unit of production basis, LOE costs decreased to $0.33 per Mcfe during the quarter ended June 30, 2018 as compared with $0.34 per Mcfe during the same period in 2017, primarily due to increased total production during the period ended June 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 rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which may increase if certain volume thresholds are exceeded.
The lease is classified as an operating lease.
For the quarter ended June 30, 2018, the Company recognized operating lease expense associated with the Lease Agreement of $6.5 million, or $0.09 per Mcfe, as compared to $5.2 million, or $0.08 per Mcfe for the same period in 2017.
Production Taxes.
During the quarter ended June 30, 2018, production taxes decreased to $18.9 million compared to $21.8 million during the same period in 2017, or $0.27 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 9.9% of revenues for the quarter ended June 30, 2018 and 10.2% 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 June 30, 2018 as compared to the same period in 2017.
Gathering Fees.
During the quarter ended June 30, 2018, gathering fees increased to $24.2 million compared to $20.6 million during the same period in 2017, largely related to increased production. On a per unit basis, gathering fees increased to $0.34 per Mcfe for the quarter ended June 30, 2018 compared with $0.31 per Mcfe for the same period in 2017.
Depletion, Depreciation and Amortization.
During the quarter ended June 30, 2018, DD&A expense increased to $51.7 million compared to $38.7 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 as a result of increased production volumes during the quarter ended June 30, 2018. On a unit of production basis, the DD&A rate increased to $0.73 per Mcfe for the quarter ended June 30, 2018 compared to $0.58 per Mcfe for the same period in 2017.
31
General and Administrative Expenses.
During the qu
arter ended June 30, 2018, general and administrative expenses decreased to $
2.1
million as compared to $25.0 million for the same period in 2017.
The
de
crease is primarily attributable to
the $25.4 million of non-cash stock incentive compensation expense
that was incurred
during the quarter ended June 30, 2017
as
part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date
.
See Note 5 for additional details. On a per unit basis, general and administrative expenses
decreased
to $
0.03
per Mcfe for the quarter ended June 30, 2018 compared to $0.37 per Mcfe for the same period in 2017.
Other Inco
me and Expenses:
Interest Expense.
During the quarter ended June 30, 2018, interest expense of $37.7 million increased as compared to $29.4 million during the same period in 2017. The increase is primarily attributable to an increase in interest expense on the Term Loan as the amount borrowed increased year over year and increased borrowings on the Revolving Credit Facility during the quarter ended June 30, 2018. See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Notes.
Deferred Gain on Sale of Liquids Gathering System.
During the quarters ended June 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 Derivat
ives:
Gain (Loss) on Commodity Derivatives.
During the quarter ended June 30, 2018, the Company recognized a loss of $47.3 million, as compared to a gain of $20.7 million related to commodity derivatives for the same period in 2017. Of this total, the Company recognized $6.7 million related to a realized gain on commodity derivatives during the quarter ended June 30, 2018 compared with $0.9 million related to a realized loss 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 $53.9 million on commodity derivatives during the quarter ended June 30, 2018, as compared to an unrealized gain of $21.6 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
$426.8 million during the quarter ended June 30, 2017. The $426.8 million incurred is comprised of expenses of $4.3 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 proceedings and a gain of $431.1 million on the debt for equity exchanged of the 2018 Notes and 2024 Notes. See Note 10 for additional details
.
Income from Continuing Operations:
Pretax Income.
During the quarter ended June 30, 2018, the Company recognized loss before income taxes of $20.5 million compared to income before income taxes of $499.0 million for the same period in 2017. The decrease in earnings is largely attributable to the gain on the debt for equity exchange of the 2018 Notes and 2024 Notes recognized in the second 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 June 30, 2018. Some or all of this valuation allowance may be reversed in future periods against future income.
Net Income.
During the quarter ended June 30, 2018, the Company recognized net loss of $20.6 million, or $0.10 per diluted share, as compared to net income of $499.0 million, or $2.76 per diluted share, for the same period in 2017. The decrease in earnings is largely attributable to the gain on the debt for equity exchange of the 2018 Notes and 2024 Notes recognized in the second quarter of 2017 related to the Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.
32
Six Months Ended June 30, 2018 vs. Six Months Ended June 30, 2017
Production, Commodity Derivatives and Revenues:
Production.
During the six months ended June 30, 2018, total production increased by 9% on a gas equivalent basis to 143.2 Bcfe compared to 131.1 Bcfe for the same period in 2017, primarily attributable to an increase in capital investment and development activity and partially offset by the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017.
Commodity Prices – Natural Gas.
Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 17% to $2.48 per Mcf during the six months ended June 30, 2018 as compared to $2.99 per Mcf for the same period in 2017. During the six months ended June 30, 2018, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details. During the six months ended June 30, 2018, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.39 per Mcf as compared to $3.00 per Mcf for the same period in 2017.
Commodity Prices – Oil.
Realized oil prices, including realized gains and losses on commodity derivatives, increased to $59.31 per barrel during the six months ended June 30, 2018 as compared to $46.39 per barrel for the same period in 2017. During the six months ended June 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 six months ended June 30, 2018, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was $62.79 per barrel as compared to $46.39 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 $415.5 million for the six months ended June 30, 2018 as compared to $433.6 million for the same period in 2017.
Operating Costs and Expenses:
Lease Operating Expense.
LOE decreased to $45.4 million during the six months ended June 30, 2018 compared to $46.2 million during the same period in 2017, primarily related to field efficiencies in Wyoming and the sale of non-core assets in Pennsylvania during the fourth quarter of 2017. On a unit of production basis, LOE costs decreased to $0.32 per Mcfe during the six months ended June 30, 2018 compared to $0.35 per Mcfe during the same period in 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 rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. For the six months ended June 30, 2018, the Company recognized operating lease expense associated with the Lease Agreement of $12.7 million, or $0.09 per Mcfe, as compared to $10.5 million, or $0.08 per Mcfe, for the same period in 2017.
Production Taxes.
During the six months ended June 30, 2018, production taxes were $42.2 million compared to $43.9 million during the same period in 2017, or $0.29 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 six months ended June 30, 2018 and 10.1% of revenues for the same period in 2017. The decrease in per unit taxes is primarily attributable to decreased natural gas prices during the six months ended June 30, 2018 as compared to the same period in 2017.
Gathering Fees.
Gathering fees increased to $47.2 million for the six months ended June 30, 2018 compared to $41.6 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 six months ended June 30, 2018 compared to $0.32 per Mcfe for the same period in 2017.
Depletion, Depreciation and Amortization.
DD&A expenses increased to $102.3 million during the six months ended June 30, 2018 from $70.4 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 six months ended June 30, 2018 as compared to the same period in 2017 as the Company did not emerge from chapter 11 proceedings until the second quarter of 2017. On a unit of production basis, the DD&A rate increased to $0.71 per Mcfe for the six months ended June 30, 2018 compared to $0.54 per Mcfe for the six months ended June 30, 2017.
33
General and Administrative Expenses.
General and administrative expenses decreased to $
14.8
million for the six months ended June 30, 2018 compared to $26.1 million for the same period in 2017.
The
de
crease is primarily
attributable to
the $25.
2
million of non-cash stock incentive compensation expense that was incurred
during the quarter ended June 30, 2017
as
part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date
.
S
ee Note 5
for additional details. On a per unit basis, general and administrative expenses decreased to $
0.10
per Mcfe for the six months ended June 30, 2018 compared to $0.20 per Mcfe for the six months ended June 30, 2017.
Other Income and Expenses:
Interest Expense.
Interest expense decreased to $73.6 million during the six months ended June 30, 2018 compared to $114.9 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 Notes incurred during the six months ended June 30, 2018, as compared to non-recurring accrued postpetition interest for the period beginning from April 29, 2016 through April 12, 2017, which related to our chapter 11 proceedings, recognized in the six months ended June 30, 2017. See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Notes, and see Note 10 for additional details related to our chapter 11 proceedings.
Contract Settlement Expense.
During the six months ended June 30, 2017, the Company incurred $52.7 million in expense primarily 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. There were no material contract settlement expenses for the same period in 2018.
Deferred Gain on Sale of Liquids Gathering System.
During the six months ended June 30, 2018 and 2017, the Company recognized $5.3 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:
Gain (Loss) on Commodity Derivatives.
During the
six months ended June 30, 2018, the Company recognized a loss of $53.8 million related to commodity derivatives as compared to $7.5 million related to commodity derivatives during the same period in 2017. Of this total, the Company recognized $7.7 million related to realized gain on commodity derivatives during the six months ended June 30, 2018 as compared with $0.9 million related to a realized loss 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 $61.5 million unrealized loss on commodity derivatives for the six months ended June 30, 2018 as compared to a $8.4 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 $369.3 million for the six months ended June 30, 2017. The $369.3 million is primarily comprised of expenses of $61.8 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 proceedings and a gain of $431.1 million, which 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 Continuing Operations:
Pretax Income.
The Company recognized income before income taxes of $27.4 million for the six months ended June 30, 2018 compared to $409.3 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 six months ended June 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 six months ended June 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 June 30, 2018. Some or all of this valuation allowance may be reversed in future periods against future income.
34
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 six months ended June 30, 2018, the Company recognized net income of $26.9 million, or $0.14 per diluted share, as compared to $409.3 million, or $3.12 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 six months ended June 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 six months ended June 30, 2018, we funded our operations primarily through cash flows from operating activities and borrowings under the Revolving Credit Facility (defined below). At June 30, 2018, the Company reported a cash position of $5.7 million. At June 30, 2018, the Company had $58.0 million in outstanding borrowings and $367.0 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 six month period ended June 30, 2018, total capital expenditures were $251.0 million. During this period, the Company participated in 76 gross (53.3 net) wells in Wyoming that were drilled to total depth and cased. The wells drilled to total depth and cased included 61 gross (42.3 net) vertical wells and 15 gross (11.0 net) horizontal wells. No wells are scheduled to be drilled in Utah during 2018.
2018 Capital Investment Plan.
For 2018, our capital expenditures are expected to be approximately $400.0 million. We expect to fund these capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility (defined below), and cash on hand. We expect to allocate nearly all of the budget 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. There are no scheduled borrowing base redeterminations until October 1, 2018. At June 30, 2018, Ultra Resources had $58.0 million in outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $425.0.0 million and a borrowing base of $1.4 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
35
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 June 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.
Under the Revolving Credit Facility, t
he Company is subject to the following minimum hedging requirements: t
hrough 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 comply with these requirements prior to September 29, 2019 and to remain 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 June 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 June 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 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 Notes are treated as a single class of securities under the Indenture.
The 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 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 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 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 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 Notes receive investment grade ratings
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from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At June 30, 2018, Ultra Resour
ces was in compliance with all of its debt covenants under the 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 Notes, by notice to the Company and the Trustee, may, declare the 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 Notes to become due and payable.
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 six months ended June 30, 2018, net cash provided by operating activities was $205.8 million compared to $136.5 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 and partially offset by decreased oil and natural gas prices.
Investing Activities.
During the six months ended June 30, 2018, net cash used in investing activities was $272.0 million as compared to $220.3 million for the same period in 2017. The increase in net cash used in investing activities is largely related to increased capital investments associated with the Company’s drilling activities during the six months ended June 30, 2017.
Financing Activities.
During the six months ended June 30, 2018, net cash provided by financing activities was $55.3 million as compared to $120.3 million for the same period in 2017. The change in net cash provided by 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 six months ended June 30, 2017. See Note 10 for additional details.
OFF BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of June 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 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
.
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