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. is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming — the Pinedale and Jonah fields, its oil reserves in the Uinta Basin in Utah and
its natural gas reserves in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.
The Company currently conducts operations exclusively in the United States. Substantially all of its 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 and gas sales from wells located
in the Appalachian Basin in Pennsylvania. In 2014, the Company repositioned its portfolio to higher returning assets in the western U.S. while divesting lower returning assets in the eastern U.S. Additionally, as part of the acquisition of assets in
the Pinedale Field in Sublette County, Wyoming in September 2014 (the “SWEPI Transaction”), the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces in Wyoming
beginning in 2017.
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, and 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 6 to the Company’s Consolidated Financial Statements).
During the quarter ended March 31, 2016, the average price realization for the Company’s natural gas was $2.01 per Mcf compared
with $2.84 per Mcf during the quarter ended March 31, 2015. During the first quarter of 2015, the Company’s average price realization for natural gas was $3.29 per Mcf, including realized gains and losses on commodity derivatives. The
Company does not currently have any open derivative contracts for natural gas production.
During the quarter ended
March 31, 2016, the average price realization for the Company’s oil was $26.95 per barrel compared to $37.34 per barrel for the quarter ended March 31, 2015.
Liquidity and Ability to Continue as a Going Concern
As disclosed
in our most recent Annual Report on Form 10-K, because low crude oil and natural gas prices during 2015 had a significant adverse impact on our business and our financial condition, substantial doubt exists that we will be able to continue as a
going concern. Although crude oil and natural gas prices have improved
24
somewhat in recent weeks, product prices continue to be historically low, our financial condition continues to be distressed, and substantial doubt continues to exist that we will be able to
continue as a going concern. Our ability to continue as a going concern is dependent on many factors, including our ability to comply with the obligations in our existing debt agreements, to obtain waivers or other relief if we are unable to comply,
and/or to be able to repay or replace our indebtedness as it matures. We can offer no assurance that we will be able to obtain waivers or other relief, and it is unlikely we will be able to comply with all of the obligations and covenants in our
debt agreements. In addition, we have substantial unpaid principal maturities and interest payments that are past due, and we have substantial additional principal maturities and interest payments coming due in the near future. We do not have
sufficient liquidity to pay our unpaid and near-term principal maturities and interest payments without raising additional capital. We do not have sufficient liquidity to pay our indebtedness if it is accelerated and becomes immediately due and
payable without raising additional capital. Additional capital may be available only on extremely onerous terms if it is available at all. Due to our current financial constraints, including the likelihood of the occurrence of events of default
under our debt agreements, there is a substantial risk that it may be necessary for us to seek protection from our creditors under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11”) or the Canadian Bankruptcy and Insolvency Act, or an
involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada. Investors should review the disclosures and other information, including the risk factors, provided in this Quarterly Report on Form 10-Q and our most recent
Annual Report on Form 10-K.
On March 1, 2016, we entered into a Limited Waiver Agreement with the lenders under the
credit agreement between our wholly-owned subsidiary, Ultra Resources, Inc. (“Ultra Resources), as the borrower, and JPMorgan Chase Bank, as the administrative agent, and the lenders thereto (the “Credit Agreement”) (the “Bank
Waiver”) and a Waiver and Amendment to Master Note Purchase Agreement, Notes and Supplement with the holders of the unsecured senior notes issued by Ultra Resources (collectively, the “Senior Notes”) pursuant to the Master Note
Purchase Agreement dated March 6, 2008 (as supplemented, the “MNPA”) (the “MNPA Waiver” and, together with the Bank Waiver, the “Waiver Agreements”). Under the Waiver Agreements, the lenders and holders, as
applicable, party thereto agreed to waive certain specified defaults under the Credit Agreement and the MNPA, as applicable, and to forbear from exercising their rights and remedies otherwise available under the Credit Agreement and/or the MNPA, for
a forbearance period extending from March 1, 2016 until the earlier of April 30, 2016, a default or event of default under the Credit Agreement or the MNPA, as applicable, that was not waived by the Waiver Agreements, or one or more of the
termination events specified in the Waiver Agreements. During the forbearance period under the Waiver Agreements, we have attempted to and are continuing to negotiate a restructuring of our indebtedness; but, as of the date of this Quarterly Report
on Form 10-Q, we have not been successful at accomplishing our plan. In order to extend the forbearance period under the MNPA Waiver, we would be required to obtain 100% approval by the holders of the Senior Notes, which we believe is highly
unlikely.
On April 1, 2016, we elected to defer making an interest payment of approximately $26.0 million due
April 1, 2016 with respect to our 6.125% Senior Notes due 2024 (the “2024 Notes”). The indenture governing the 2024 Notes provides a 30-day grace period for us to make this interest payment. We do not expect to make this interest
payment before the end of the grace period under the indenture governing the 2024 Notes. If we do not make this interest payment before the end of the grace period, this will become an event of default under the indenture governing the 2024 Notes
and may result in the acceleration of all of our indebtedness, including the 2024 Notes. Due to our current financial constraints, including the likelihood of the occurrence of events of default under our debt agreements, there is a substantial risk
that it may be necessary for us to seek protection from our creditors under Chapter 11 or the Canadian Bankruptcy and Insolvency Act, or an involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada.
The following events have occurred since February 29, 2016 (when we filed our most recent Annual Report on Form 10-K):
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•
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On March 1, 2016, we entered into the Bank Waiver with the lenders under the Credit Agreement between Ultra Resources, as the borrower, and
JPMorgan Chase Bank, as the administrative agent, and
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25
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|
the lenders thereto, and the MNPA Waiver with 100% of the holders of the Senior Notes issued by Ultra Resources pursuant to the MNPA. The Waiver Agreements were effective March 1, 2016 and
provide for a forbearance period extending through no later than April 30, 2016. These events were disclosed in our Current Report on Form 8-K filed March 2, 2016.
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•
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On March 1, 2016, we elected not to make a $62.0 million principal payment due under the unsecured senior notes issued by Ultra Resources. Because
of the Waiver Agreements, this is not a default under the MNPA during the forbearance period under the Waiver Agreements.
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•
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On March 1, 2016, we elected not to make a $40.0 million interest payment due under the unsecured senior notes issued by Ultra Resources. Because
of the Waiver Agreements, this is not a default under the MNPA during the forbearance period under the Waiver Agreements.
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•
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On March 8, 2016, we received a letter from Sempra Rockies Marketing, LLC (“Sempra”) notifying us that Sempra was exercising its alleged
right to permanently recall the 50,000 MMBtu/day of capacity on the Rockies Express pipeline and that the recall would be effective as of March 9, 2016. We had previously received a letter, dated February 26, 2016, from Sempra alleging
that we were in breach of our Capacity Release Agreement, dated March 5, 2009, due to nonpayment of fees for transportation service and notifying us that Sempra was authorized to recall the capacity released to us under the agreement and to
pursue any claims for damages or other remedies to which Sempra was entitled.
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•
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On March 11, 16, 21, and 31, 2016, we elected not to make a total of $2.7 million of interest payments due under the Credit Agreement. Because of
the Waiver Agreements, this is not a default under the Credit Agreement during the forbearance period under the Waiver Agreements.
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•
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On March 15, 2016, we delivered, to the lenders under the Credit Agreement, an audit report prepared by our auditors with respect to the financial
statements in our most recent Annual Report on Form
10-K,
which included an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The Credit Agreement
requires us to deliver annual audited, consolidated financial statements without a “going concern” or like qualification or explanation. The Credit Agreement provides a 30-day grace period related to this requirement. Because of the Waiver
Agreements, this is not a default under the Credit Agreement during the forbearance period under the Waiver Agreements.
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•
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On March 15, 2016, we received a notice from the New York Stock Exchange (“NYSE”) that we were not in compliance with the NYSE’s
continued listing standards, and, as a result, there is a significant risk our common stock will be delisted from the NYSE. This event was disclosed in our Current Report on Form 8-K filed March 18, 2016.
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•
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On March 28, 2016, we received a letter from Rockies Express Pipeline notifying us that, according to Rockies Express, our transportation
agreement had terminated effective as of March 26, 2016 due to our alleged defaults under the terms of the Rockies Express tariff and our transportation agreement.
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•
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On April 1, 2016, we notified the lenders under the Credit Agreement of the annual redetermination of the PV-9 value of our proved reserves. The
Credit Agreement requires Ultra Resources to maintain a minimum ratio of the discounted net present value of its oil and gas properties to its total funded consolidated debt of 1.5 times. Based on the PV-9 of its oil and gas properties at
December 31, 2015, Ultra Resources failed to comply with the PV-9 ratio covenant (the ratio was 0.9 times at March 31, 2016). Because of the Waiver Agreements, this is not a default under the Credit Agreement during the forbearance period
under the Waiver Agreements.
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•
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On April 1, 2016, we elected to defer making an interest payment of approximately $26.0 million due April 1, 2016 with respect to our 2024
Notes. The indenture governing the 2024 Notes provides a
30-day
grace period for us to make this interest payment. If we make this interest payment before the end of the forbearance period under the Waiver
Agreements, the waivers and forbearances granted by our lenders in the Waiver Agreements will terminate. This event was disclosed in our Current Report on Form 8-K filed April 1, 2016.
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26
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•
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On April 4, 2016, we received a demand for payment and notice of enforcement from Rockies Express related to our transportation agreement on
Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016.
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•
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On April 14, 2016, Rockies Express filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages related to
the alleged breach. We intend to defend this lawsuit vigorously.
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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, 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 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 three months ended March 31, 2016 and 2015 was $1.8 million and $2.0 million, respectively. See Note 4 for additional information.
Property, Plant and Equipment.
Capital assets are recorded at cost and depreciated using the declining-balance method based
on their respective useful life.
27
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 three months ended
March 31, 2016 or 2015.
Capitalized Interest.
Interest is capitalized on the cost of unevaluated gas and
oil properties that are excluded from amortization and actively being evaluated, if any (See Note 2).
Revenue
Recognition.
The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the
customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.”
Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes.
Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its
partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of
accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet
recognition of the estimated value of product imbalance. The Company’s imbalance obligations as of March 31, 2016 and December 31, 2015 were immaterial.
28
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.
The Company has recorded a valuation allowance against certain of its deferred tax assets as of March 31, 2016. Some or all of this valuation allowance may be reversed in future periods against
future income.
Deferred Financing Costs.
Included in other current assets at March 31, 2016 are costs
associated with the issuance of our revolving credit facility. Costs associated with the issuance of our Senior Notes, 2018 Notes and 2024 Notes are presented in the balance sheet as a direct deduction from the carrying amount of the related debt
liability. The remaining unamortized issuance costs are being amortized over the life of the applicable debt or facility using the straight line method.
Recent accounting pronouncements.
In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09,
Compensation-Stock Compensation (Topic 718): Improvements to
Employee Share-Based Payment Accounting
(“ASU No. 2016-09”) to simplify some of the provisions in stock compensation accounting. The update simplifies the accounting for a stock payment’s tax consequences and amends how
excess tax benefits and a business’s payments to cover the tax bills for the shares’ recipients should be classified. The amendments allow companies to estimate the number of stock awards expected to vest and revises the withholding
requirements for classifying stock awards as equity. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 with earlier application permitted. The
Company is still evaluating the impact of ASU No. 2016-09 on its financial position and results of operations.
In
February 2016, the FASB issued Accounting Standards Update (“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 also will 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. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations.
In November 2015, the FASB issued ASU 2015-17,
Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
(“ASU No. 2015-17”). The guidance eliminates the requirement
to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective
for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting
period and may be applied either prospectively or retrospectively to all periods presented. The Company has elected early adoption of ASU No. 2015-17 and has applied these changes prospectively. The adoption of this guidance has no impact on
our results of operations or cash flows. The reclassification of amounts from current to noncurrent affects presentation of our financial position. See Note 9 for additional information.
In July 2015, the FASB issued ASU 2015-11,
Inventory (Topic 330): Simplifying the Measurement of Inventory
(“ASU
No. 2015-11”). Public companies will have to apply the amendments for reporting periods that
29
start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net
realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material
impact on its consolidated financial statements.
In April 2015, the FASB issued ASU 2015-03,
Interest — Imputation of
Interest (Subtopic 835-30) — Simplifying the Presentation of Debt Issuance Costs.
In August 2015, the FASB issued ASU 2015-15,
Interest — Imputation of Interest (Subtopic 835-30) — Presentation and Subsequent Measurement of
Debt Issuance Costs Associated with Line-of-Credit Arrangements
. These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the
carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced current assets and current
maturities of long-term debt by $19.2 million and $19.4 million on the Company’s Consolidated Balance Sheet at March 31, 2016 and December 31, 2015, respectively.
In June 2015, the FASB issued a delay by one year of the revenue recognition standard adopted in June 2014. In June 2014, the FASB issued
ASU No. 2014-09,
Revenue from Contracts with Customers (Topic 606)
(“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606,
Revenue from Contracts with Customers
, and superseding the revenue
recognition requirements in FASB ASC 605,
Revenue Recognition
, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the
nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. The new proposal related to ASU No. 2014-09 delays the application of the standard to reporting periods beginning after December 15, 2017
instead of December 15, 2016. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations.
In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that requires management
to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis.
Management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes
effective for annual periods beginning after December 15, 2016 and for interim reporting periods thereafter. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.
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.
30
RESULTS OF OPERATIONS:
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For the Three Months
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Ended March 31,
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%
Variance
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2016
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2015
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(Amounts in thousands, except per unit data)
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Production, Commodity Prices and Revenues:
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Production:
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Natural gas (Mcf)
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68,605
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|
|
64,704
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|
6
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%
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|
Crude oil and condensate (Bbls)
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|
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790
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|
951
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|
-17
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%
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Total production (Mcfe)
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73,345
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70,410
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|
4
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%
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Commodity Prices:
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Natural gas ($/Mcf, excluding hedges)
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$
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2.01
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$
|
2.84
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-29
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%
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Natural gas ($/Mcf, including realized hedges)
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$
|
2.01
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|
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$
|
3.29
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-39
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%
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Oil and condensate ($/Bbl)
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$
|
26.95
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$
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37.34
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-28
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%
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Revenues:
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Natural gas sales
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$
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138,102
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$
|
183,795
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-25
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%
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|
Oil sales
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21,284
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|
|
35,514
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|
|
|
-40
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%
|
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Total operating revenues
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$
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159,386
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|
|
$
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219,309
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-27
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%
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Derivatives:
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Realized gain (loss) on commodity derivatives-natural gas
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|
$
|
—
|
|
|
$
|
29,359
|
|
|
|
100
|
%
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
—
|
|
|
|
7,506
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on commodity derivatives
|
|
$
|
—
|
|
|
$
|
36,865
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
25,394
|
|
|
$
|
26,112
|
|
|
|
-3
|
%
|
|
Liquids gathering system operating lease expense
|
|
$
|
5,171
|
|
|
$
|
5,162
|
|
|
|
0
|
%
|
|
Production taxes
|
|
$
|
15,231
|
|
|
$
|
19,895
|
|
|
|
-23
|
%
|
|
Gathering fees
|
|
$
|
22,450
|
|
|
$
|
19,757
|
|
|
|
14
|
%
|
|
Transportation charges
|
|
$
|
23,555
|
|
|
$
|
20,191
|
|
|
|
17
|
%
|
|
Depletion, depreciation and amortization
|
|
$
|
30,848
|
|
|
$
|
94,590
|
|
|
|
-67
|
%
|
|
General and administrative expenses
|
|
$
|
4,219
|
|
|
$
|
3,640
|
|
|
|
16
|
%
|
|
|
|
|
|
|
Per Unit Costs and Expenses ($/Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.35
|
|
|
$
|
0.37
|
|
|
|
-5
|
%
|
|
Liquids gathering system operating lease expense
|
|
$
|
0.07
|
|
|
$
|
0.07
|
|
|
|
0
|
%
|
|
Production taxes
|
|
$
|
0.21
|
|
|
$
|
0.28
|
|
|
|
-25
|
%
|
|
Gathering fees
|
|
$
|
0.31
|
|
|
$
|
0.28
|
|
|
|
11
|
%
|
|
Transportation charges
|
|
$
|
0.32
|
|
|
$
|
0.29
|
|
|
|
10
|
%
|
|
Depletion, depreciation and amortization
|
|
$
|
0.42
|
|
|
$
|
1.34
|
|
|
|
-69
|
%
|
|
General and administrative expenses
|
|
$
|
0.06
|
|
|
$
|
0.05
|
|
|
|
20
|
%
|
Quarter Ended March 31, 2016 vs. Quarter Ended March 31, 2015
Production, Commodity Derivatives and Revenues:
Production.
During the quarter ended March 31, 2016, total production increased 4% on a gas equivalent basis to 73.3 Bcfe compared to 70.4 Bcfe for the same quarter in 2015. The increase is
primarily attributable to our drilling program in 2015.
Commodity Prices — Natural Gas.
Realized natural gas
prices decreased 29% to $2.01 per Mcf in the first quarter of 2016 as compared to $2.84 per Mcf for the same quarter of 2015. The Company does not currently
31
have any open derivative contracts for natural gas production. During the three months ended March 31, 2015, the Company’s average price for natural gas including realized gains and
losses on commodity derivatives was $3.29 per Mcf.
Commodity Prices — Oil.
During the quarter ended
March 31, 2016, the average price realization for the Company’s oil was $26.95 per barrel compared to $37.34 per barrel for the same period in 2015. The Company does not currently have any open derivative contracts for oil production.
Revenues.
The decrease in average oil and natural gas prices, offset by increased production from our drilling program
resulted in revenues decreasing to $159.4 million for the quarter ended March 31, 2016 as compared to $219.3 million for the same period in 2015.
Operating Costs and Expenses:
Lease Operating Expense.
Lease
operating expense (“LOE”) remained relatively flat at $25.4 million during the first quarter of 2016 compared to $26.1 million during the same period in 2015. On a unit of production basis, LOE costs decreased to $0.35 per Mcfe during the
first quarter of 2016 compared with $0.37 per Mcfe during the first quarter of 2015 largely related to increased production volumes during the period ended March 31, 2016.
Liquids Gathering System Operating 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 for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and
may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. For the three months ended March 31, 2016, the Company recognized operating lease expense associated with the Lease Agreement of $5.2
million, or $0.07 per Mcfe as compared to $5.2 million, or $0.07 per Mcfe for the same period in 2015.
Production
Taxes.
During the three months ended March 31, 2016, production taxes were $15.2 million compared to $19.9 million during the same period in 2015, or $0.21 per Mcfe compared to $0.28 per Mcfe. Production taxes are primarily calculated based
on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 9.6% of revenues for the quarter ended March 31, 2016 and 9.1% of revenues for the same period in 2015. The decrease in per unit taxes is primarily
attributable to decreased oil and natural gas prices during the quarter ended March 31, 2016 as compared to the same period in 2015.
Gathering Fees.
Gathering fees increased to $22.5 million for the three months ended March 31, 2016 compared to $19.8 million during the same period in 2015 largely related to production
increases in Wyoming. On a per unit basis, gathering fees increased to $0.31 per Mcfe for the three months ended March 31, 2016 as compared to $0.28 per Mcfe during the same period in 2015 primarily due to higher gathering rates associated with
the low pressure system in the Pinedale field.
Transportation Charges.
Transportation charges in association with
Rockies Express Pipeline (“REX”) increased to $23.6 million for the quarter ended March 31, 2016 as compared to $20.2 million for the same period in 2015 primarily as a result of reduced royalty deductions. On a per unit basis,
transportation charges increased to $0.32 per Mcfe (on total company volumes) for the quarter ended March 31, 2016 compared with $0.29 per Mcfe (on total company volumes) for the quarter ended March 31, 2015. See Note 9 for further
discussion of the REX contract.
Depletion, Depreciation and Amortization.
DD&A expenses decreased to $30.8 million
during the three months ended March 31, 2016 from $94.6 million for the same period in 2015, primarily attributable to a
32
decreased DD&A rate on a unit of production basis as a result of the ceiling test impairment during the fourth quarter of 2015. On a unit of production basis, the DD&A rate decreased to
$0.42 per Mcfe for the quarter ended March 31, 2016 compared to $1.34 per Mcfe for the quarter ended March 31, 2015.
General and Administrative Expenses.
General and administrative expenses remained relatively flat at $4.2 million for the quarter
ended March 31, 2016 compared to $3.6 million for the same period in 2015. On a per unit basis, general and administrative expenses remained relatively flat at $0.06 per Mcfe for the quarter ended March 31, 2016 compared to $0.05 per Mcfe
for the quarter ended March 31, 2015.
Other Income and Expenses:
Interest Expense.
Interest expense increased to $49.9 million during the quarter ended March 31, 2016 compared to $42.7
million during the same period in 2015 primarily as a result of higher average borrowings outstanding for the quarter ended March 31, 2016 as compared to the same period in 2015 and decreased amounts of capitalized interest for the quarter
ended March 31, 2016 as compared to the same period in 2015. For the quarter ended March 31, 2016, the Company did not capitalize any interest associated with unevaluated oil and gas properties that are excluded from amortization compared
with $3.2 million in capitalized interest for the quarter ended March 31, 2015.
Debt Restructuring Fees.
During
the quarter ended March 31, 2016, the Company incurred $5.6 million in costs and fees in connection with its efforts to restructure its debt.
Deferred Gain on Sale of Liquids Gathering System.
During the quarters ended March 31, 2016 and 2015, the Company recognized $2.6 million in deferred gain on sale of the liquids gathering
system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.
Commodity Derivatives:
Gain/(Loss) on Commodity Derivatives.
The Company does not currently have any open commodity derivative contracts. During the quarter ended March 31, 2015, the Company recognized a gain of $36.9 million related to commodity derivatives. Of this total, the Company recognized
$29.4 million of realized gain on commodity derivatives during the quarter ended March 31, 2015. 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. This amount also includes an unrealized gain on commodity derivatives of $7.5 million during the quarter ended March 31, 2015. 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. See Note 6.
(Loss) Income from Continuing Operations:
Pretax (Loss) Income.
The Company recognized a net loss before income taxes of $22.0 million for the quarter
ended March 31, 2016 compared with income before income taxes of $23.2 million for the same period in 2015. The decrease in earnings is primarily due to decreased revenues, including gains on commodity derivatives, as a result of decreased oil
and natural gas prices during the three months ended March 31, 2016 as compared to the same period in 2015 and partially offset by decreased DD&A during the three months ended March 31, 2016.
Income Taxes.
The Company has recorded a valuation allowance against certain deferred tax assets as of March 31, 2016. Some
or all of this valuation allowance may be reversed in future periods against future income.
Net (Loss) Income.
For the
three months ended March 31, 2016, the Company recognized net loss of $21.8 million or $0.14 per diluted share as compared with net income of $25.2 million or $0.16 per diluted share for the
33
same period in 2015. The decrease in earnings is primarily due to decreased revenues, including gains on commodity derivatives, as a result of decreased oil and natural gas prices during the
three months ended March 31, 2016 as compared to the same period in 2015 and partially offset by decreased DD&A during the three months ended March 31, 2016.
LIQUIDITY AND CAPITAL RESOURCES
Waiver Agreements.
On
March 1, 2016, we entered into the Waiver Agreements. Under the Waiver Agreements, the lenders party thereto agreed to waive certain specified defaults under the Credit Agreement and the MNPA, and to forbear from exercising their rights and
remedies otherwise available under the Credit Agreement and/or the MNPA, for a forbearance period extending from March 1, 2016 until the earlier of April 30, 2016, a default or event of default under the Credit Agreement that was not
waived by the Waiver Agreements, or one or more of the termination events specified in the Waiver Agreements. During the forbearance period under the Waiver Agreements, we have attempted to and are continuing to negotiate a restructuring of our
indebtedness, but, as of the date of this Quarterly Report on Form 10-Q, we have not been successful at accomplishing our plan. In order to extend the forbearance period under the MNPA Waiver, we would be required to obtain 100% approval by the
holders of the Senior Notes, which we believe is highly unlikely.
Overview.
During the three month period ended
March 31, 2016, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. At March 31, 2016, the Company reported a cash position of $281.5
million compared to $34.0 million at March 31, 2015.
Capital Expenditures.
For the three month period
ended March 31, 2016, total capital expenditures were $76.7 million. During this period, the Company participated in 32 gross (22.4 net) wells in Wyoming that were drilled to total depth and cased. No wells are scheduled to be drilled in Utah
or Pennsylvania during 2016.
Working Capital.
Working capital deficit at March 31, 2016 was $3.6 billion
compared to working capital deficit of $76.1 million at March 31, 2015. At March 31, 2016, the Company had $999.0 million in outstanding borrowings, representing substantially all of the remaining undrawn amount under the Credit Agreement.
As a result, no material further extensions of credit are available under the Credit Agreement. In addition, the Company had $2.76 billion outstanding in senior notes (See Note 3). Other long-term obligations of $177.6 million at March 31, 2016
were comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.
Continued low oil and natural gas prices have had a significant adverse impact on our business, and, as a result of our financial
condition, substantial doubt exists that we will be able to continue as a going concern. As a result, we have reclassified all of our total outstanding debt as short-term. A failure by us to comply with our financial covenants or to comply with the
other restrictions in our financing agreements may result in reduced borrowing capacity or an event of a default under the agreements governing our indebtedness, causing our debt obligations under such financing agreements (and any other
indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable.
Maturities.
At March 31, 2016, we have the following obligations outstanding under the Credit Agreement, the 2018
Notes, the 2024 Notes, and the Senior Notes (maturity dates exclude the effect of the default provisions):
|
|
•
|
|
$999.0 million due October 2016 under the Credit Agreement;
|
|
|
•
|
|
$450.0 million due December 2018 with respect to the 2018 Notes;
|
|
|
•
|
|
$850.0 million due September 2024 with respect to the 2024 Notes; and
|
|
|
•
|
|
$1.46 billion due between March 2016 and October 2025 with respect to the Senior Notes.
|
34
A $62.0 million maturity payment under one series of the Senior Notes was due March 1,
2016 but was not paid. This is not a default under the MNPA during the forbearance period under the Waiver Agreements. However, because of our financial constraints and the significant level of our indebtedness compared to our expected business
performance, we do not expect to pay this maturity before the forbearance period ends. Once the forbearance period under the Waiver Agreements ends, unless all of the parties holding our Senior Notes grant a further waiver or other relief related to
this requirement, our failure to pay this maturity will become an Event of Default under the MNPA.
Going
Concern.
As disclosed in our most recent Annual Report on Form 10-K, because low crude oil and natural gas prices during 2015 had a significant adverse impact on our business and our financial condition, substantial doubt exists that we will
be able to continue as a going concern. Although crude oil and natural gas prices have improved somewhat in recent weeks, product prices continue to be historically low, our financial condition continues to be distressed, and substantial doubt
continues to exist that we will be able to continue as a going concern. Our ability to continue as a going concern is dependent on many factors, including our ability to comply with the obligations in our existing debt agreements, to obtain waivers
or other relief if we are unable to comply, and/or to be able to repay or replace our indebtedness as it matures. We can offer no assurance that we will be able to obtain waivers or other relief, and we do not expect to be able to comply with the
obligations and covenants in our debt agreements. We also do not have sufficient liquidity to repay our indebtedness if it is accelerated and becomes immediately due and payable. Due to our current financial constraints, including the likelihood of
the occurrence of events of default under our debt agreements, there is a substantial risk that it may be necessary for us to seek protection from our creditors under Chapter 11 or the Canadian Bankruptcy and Insolvency Act, or an involuntary
petition for bankruptcy may be filed against us in the U.S. or in Canada.
In order to increase the Company’s liquidity
to levels sufficient to meet the Company’s commitments, we are currently pursuing or considering a number of actions including: (i) in- and out-of-court restructuring, (ii) minimizing our capital expenditures, (iii) obtaining
waivers or amendments from our lenders, (iv) effectively managing our working capital and (v) improving our cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these
transactions or that these transactions can be consummated within the period needed to meet certain obligations.
Investors
should review the disclosures and other information, including the risk factors, provided in this Quarterly Report on Form 10-Q and our most recent Annual Report on Form 10-K. For additional discussion of factors that may affect our ability to
continue as a going concern and the potential consequences of our failure to do so, please see the risk factors in this Quarterly Report on Form 10-Q and Item 1A — Risk Factors in our Form 10-K for the year ended December 31, 2015,
filed February 29, 2016.
2016 Capital Investment Plan.
For 2016, our original capital budget was $260.0
million, reflecting the low commodity price environment at the beginning of the year. On April 26, 2016, our Board of Directors approved an increase to our capital budget for 2016 from $260.0 million to $295.0 million. We anticipate using the
additional capital in our increased budget to complete some of our uncompleted wells in Utah and to drill additional development wells in Wyoming. We expect to fund our 2016 capital expenditures budget through cash flows from operations and cash on
hand.
Subsequent Events.
The Company has evaluated the period subsequent to March 31, 2016 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:
|
|
•
|
|
On April 1, 2016, we elected to defer making an interest payment of approximately $26.0 million due April 1, 2016 with respect to the 2024
Notes. The indenture governing the 2024 Notes provides a
30-day
grace period for us to make this interest payment. If we make this interest payment before the end of the forbearance period under the Waiver
Agreements, the waivers and forbearances granted by our lenders in the Waiver Agreements will terminate.
|
35
|
|
•
|
|
On April 4, 2016, we received a demand for payment and notice of enforcement from Rockies Express related to our transportation agreement on
Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016
|
|
|
•
|
|
On April 14, 2016, Rockies Express filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages relating to
the alleged breach. We intend to defend this lawsuit vigorously.
|
|
|
•
|
|
On April 19, 2016, the Company received a preliminary determination notice from ONRR asserting that the Company’s allocation of certain
processing costs and plant fuel use at a specific processing plant were impermissibly allowed as deductions in the determination of royalties owed under Federal oil and gas leases. The Company intends to submit a response to the preliminary
determination asserting the reasonableness of its allocation methodology of such costs. This ONRR unbundling review could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for
current and prior periods.
|
Ultra Resources, Inc.
Bank indebtedness.
The Company (through its subsidiary, Ultra Resources) is a party to the Credit Agreement with a syndicate
of banks led by JP Morgan Chase Bank, N.A. Ultra Resources’ obligations under the Credit Agreement are guaranteed by the Company and UP Energy Corporation, a wholly-owned subsidiary of the Company. The Credit Agreement provides a loan
commitment of $1.0 billion. At March 31, 2016, the Company had $999.0 million in outstanding borrowings, representing substantially all of the remaining undrawn amount under the Credit Agreement.
Except as otherwise provided in the Waiver Agreements, loans under the Credit Agreement are unsecured and bear interest, at the
Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 150 basis points per annum as of March 31, 2016, or
(B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (250 basis points per annum as of March 31, 2016). Under the Bank Waiver, our outstanding
indebtedness incurred pursuant to the Credit Agreement will accrue interest at the contract rate otherwise applicable to such debt, except that unpaid interest that comes due and payable during the forbearance period under the Waiver Agreements
accrues interest at the rate applicable thereto plus two percent per annum. We are required to pay commitment fees on the unused commitment amount under the Credit Agreement based on Ultra Resources’ consolidated leverage ratio.
The Credit Agreement contains typical and customary representations, warranties, covenants and events of default.
The Credit Agreement requires us to deliver annual audited, consolidated financial statements for the Company without a “going
concern” or like qualification or explanation. On March 15, 2016, we delivered an audit report with respect to the financial statements in our most recent Annual Report on Form 10-K that included an explanatory paragraph expressing
uncertainty as to our ability to continue as a “going concern.” The Credit Agreement provides a 30-day grace period related to this requirement. In addition, this is not a default under the Credit Agreement during the forbearance period
under the Waiver Agreements. Because we cannot comply with this requirement under the Credit Agreement, once the forbearance period under the Waiver Agreements ends, unless the lenders under the Credit Agreement grant a further waiver or other
relief related to this requirement, our failure to deliver the required financial statements will become an Event of Default under the Credit Agreement.
The Credit Agreement contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal
quarters’ EBITDAX of three and one half times to one. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31,
2016 (the ratio was 4.6 times at March 31, 2016). This is not a default under the Credit Agreement
36
during the forbearance period under the Waiver Agreements. However, because we cannot comply with this requirement under the Credit Agreement, once the forbearance period under the Waiver
Agreements ends, unless the lenders under the Credit Agreement grant a further waiver or other relief related to this requirement, our failure to comply with the consolidated leverage covenant will become an Event of Default under the Credit
Agreement.
The Credit Agreement contains a PV-9 covenant, pursuant to which Ultra Resources is required to maintain a minimum
ratio of the discounted net present value of its oil and gas properties to its total funded consolidated debt of 1.5 times. We were required to report whether we were in compliance with this covenant on April 1, 2016. Based on the PV-9 of Ultra
Resources’ oil and gas properties at December 31, 2015, Ultra Resources failed to comply with the PV-9 ratio covenant under the Credit Agreement (the ratio was 0.9 times at March 31, 2016). This is not a default under the Credit
Agreement during the forbearance period under the Waiver Agreements. However, because we cannot comply with this requirement under the Credit Agreement, once the forbearance period under the Waiver Agreements ends, unless the lenders under the
Credit Agreement grant a further waiver or other relief related to this requirement, our failure to comply with the PV-9 covenant will become an Event of Default under the Credit Agreement.
Senior Notes.
Ultra Resources has outstanding $1.46 billion of Senior Notes. Ultra Resources’ Senior Notes rank pari
passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole
premium and are subject to representations, warranties, covenants and events of default similar to those in the Credit Agreement.
The MNPA contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal
quarters’ EBITDAX of 3.5 to 1.0. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31, 2016 (the ratio was
4.6 times at March 31, 2016). This is not a default under the MNPA during the forbearance period under the Waiver Agreements. However, because we cannot comply with this requirement under the MNPA, once the forbearance period under the Waiver
Agreements ends, unless the noteholders of the Senior Notes grant a further waiver or other relief related to this requirement, our failure to comply with the consolidated leverage covenant will become an Event of Default under the MNPA.
The MNPA Waiver provides that during the forbearance period under the Waiver Agreements, the outstanding indebtedness under the Senior
Notes will accrue interest at the contract rate otherwise applicable to such debt, except that the $40.0 million of unpaid interest which was due March 1, 2016 and the $62.0 million of unpaid principal which was due March 1, 2016 will
accrue interest at the rate applicable thereto plus two percent per annum.
Ultra Petroleum Corp. Senior Notes
Senior Notes due 2024
: On September 18, 2014, the Company issued $850.0 million of 2024 Notes. The
2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all
future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and, as a result, are structurally subordinated to the
indebtedness and other obligations of the Company’s subsidiaries. On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal
amount of the 2024 Notes: 2019 – 103.063%; 2020 – 102.042%; 2021 – 101.021%; and 2022 and thereafter – 100.000%. The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make
distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At
March 31, 2016, the Company was in
37
compliance with all of its debt covenants under the 2024 Notes. However, as noted above with respect to the Credit Agreement and the Ultra Resources Senior Notes, once the forbearance period
under the Waiver Agreements ends, unless the Ultra Resources lenders grant a further waiver or other relief, violations of covenants or events of nonpayment under the Credit Agreement and/or the Senior Notes will become Events of Default under the
Credit Agreement and/or the MNPA and could also become Events of Default under the 2024 Notes, potentially resulting in the acceleration of all of our indebtedness, including the 2024 Notes.
Interest due under the 2024 Notes is payable each April 1 and October 1. On April 1, 2016, we elected to defer making an
interest payment on the 2024 Notes of approximately $26.0 million due April 1, 2016. The indenture governing the 2024 Notes provides a 30-day grace period for us to make this interest payment. If we make this interest payment before the end of
the forbearance period under the Waiver Agreements, the waivers and forbearances granted by our lenders in the Waiver Agreements will terminate. We do not expect to make this interest payment before the end of the grace period under the indenture
governing the 2024 Notes. If we do not make this interest payment before the end of the grace period, this will become an event of default under the indenture governing the 2024 Notes and may result in the acceleration of all of our indebtedness,
including the 2024 Notes.
Senior Notes due 2018
: On December 12, 2013, the Company issued $450.0 million
of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior
indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries
and, as a result, are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. As of December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following
prices expressed as a percentage of principal amount of the 2018 Notes: 2015 – 102.875%; 2016 – 101.438%; and 2017 and thereafter – 100.000%. The 2018 Notes are subject to covenants that restrict the Company’s ability to incur
indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2018 Notes contain events of default customary for a senior note
financing. Interest due under the 2018 Notes is payable each June 15 and December 15. At March 31, 2016, the Company was in compliance with all of its debt covenants under the 2018 Notes. However, as noted above with respect to the
Credit Agreement and the Ultra Resources Senior Notes, once the forbearance period under the Waiver Agreements ends, unless the Ultra Resources lenders grant a further waiver or other relief, violations of covenants or events of nonpayment under the
Credit Agreement and/or the Senior Notes will become Events of Default under the Credit Agreement and/or the MNPA and could also become Events of Default under the 2018 Notes, potentially resulting in the acceleration of all of our indebtedness,
including the 2018 Notes.
Operating Activities.
During the three months ended March 31, 2016, net cash
used in operating activities was $3.7 million, a 103% decrease from net cash provided by operating activities of $121.8 million for the same period in 2015. The decrease in net cash used in operating activities is largely attributable to decreased
revenues as a result of decreased oil and natural gas price realizations during the three months ended March 31, 2016 as compared to the same period in 2015 and net changes in working capital.
Investing Activities.
During the three months ended March 31, 2016, net cash used in investing activities was $87.6
million as compared to $140.3 million for the same period in 2015. The decrease in net cash used in investing activities is largely related to decreased capital investments associated with the Company’s drilling activities.
Financing Activities.
During the three months ended March 31, 2016, net cash provided by financing activities was
$368.7 million compared to $43.5 million for the same period in 2015. The change in net cash provided by financing activities is primarily due to increased borrowings during 2016 related to drawings under the Credit Agreement.
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Outlook
As disclosed in our most recent Annual Report on Form 10-K, low crude oil and natural gas prices during 2015 have had and continue to have a significant adverse impact on our business and our financial
condition. We have significant indebtedness, and because we are experiencing a period of financial distress due in part to low commodity prices, substantial doubt exists that we will be able to continue as a going concern. Our ability to continue as
a going concern is dependent on many factors, including our ability to comply with the obligations in our existing debt agreements, to obtain waivers or other relief if we are unable to comply, and/or to be able to repay or replace our indebtedness
as it matures. We can offer no assurance that we will be able to obtain waivers or other relief, and it is unlikely we will be able to comply with all of the obligations and covenants in our debt agreements. In addition, we have substantial unpaid
principal maturities and interest payments that are past due, and we have substantial additional principal maturities and interest payments coming due in the near future. We do not have sufficient liquidity to pay our unpaid and near-term principal
maturities and interest payments without raising additional capital. We do not have sufficient liquidity to pay our indebtedness if it is accelerated and becomes immediately due and payable without raising additional capital. Additional capital may
be available only on extremely onerous terms if it is available at all.
We have been working to amend, replace, refinance or
restructure our debt agreements or to secure additional capital to alleviate our financial distress. On March 1, 2016, we entered into the Waiver Agreements. Under the Waiver Agreements, the lenders party thereto agreed to waive certain
specified defaults under the Credit Agreement and the MNPA, and to forbear from exercising their rights and remedies otherwise available under the Credit Agreement and/or the MNPA, for a forbearance period extending from March 1, 2016 until the
earlier of April 30, 2016, a default or event of default under the Credit Agreement that was not waived by the Waiver Agreements, or one or more of the termination events specified in the Waiver Agreements.
During the forbearance period under the Waiver Agreements, we have attempted to and are continuing to negotiate a restructuring of our
indebtedness, but, as of the date of this Quarterly Report on Form 10-Q, we have not been successful at accomplishing our plan. In order to extend the forbearance period under the MNPA Waiver, we would be required to obtain 100% approval by the
holders of the Senior Notes, which we believe is highly unlikely.
On April 1, 2016, we elected to defer making an
interest payment of approximately $26.0 million due April 1, 2016 with respect to our 2024 Notes. The indenture governing the 2024 Notes provides a 30-day grace period for us to make this interest payment. We do not expect to make this interest
payment before the end of the grace period under the indenture governing the 2024 Notes. If we do not make this interest payment before the end of the grace period, this will become an event of default under the indenture governing the 2024 Notes
and may result in the acceleration of all of our indebtedness, including the 2024 Notes. Due to our current financial constraints, including the likelihood of the occurrence of events of default under our debt agreements, there is a substantial risk
that it may be necessary for us to seek protection from our creditors under Chapter 11 or the Canadian Bankruptcy and Insolvency Act, or an involuntary petition for bankruptcy may be filed against us in the U.S. or in Canada.
OFF BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of March 31, 2016.
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
of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 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
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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, 2015 and the risk factors provided in this Quarterly Report on Form 10-Q for
additional risks related to the Company’s business.