UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2014
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-33614
ULTRA PETROLEUM CORP.
(Exact name of registrant as specified in its charter)
Yukon Territory, Canada | N/A | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. employer identification number) | |
400 North Sam Houston Parkway E., Suite 1200, Houston, Texas |
77060 | |
(Address of principal executive offices) | (Zip code) |
(281) 876-0120
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO x
The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of July 21, 2014 was 153,215,746.
PART I FINANCIAL INFORMATION | ||||||
ITEM 1. |
Financial Statements | 3 | ||||
ITEM 2. |
Managements Discussion and Analysis of Financial Condition and Results of Operations | 18 | ||||
ITEM 3. |
Quantitative and Qualitative Disclosures About Market Risk | 29 | ||||
ITEM 4. |
Controls and Procedures | 31 | ||||
PART II OTHER INFORMATION | ||||||
ITEM 1. |
Legal Proceedings | 32 | ||||
ITEM 1A. |
Risk Factors | 32 | ||||
ITEM 2. |
Unregistered Sales of Equity Securities and Use of Proceeds | 32 | ||||
ITEM 3. |
Defaults upon Senior Securities | 32 | ||||
ITEM 4. |
Mine Safety Disclosures | 32 | ||||
ITEM 5. |
Other Information | 32 | ||||
ITEM 6. |
Exhibits | 33 | ||||
Signatures | 34 | |||||
Exhibit Index | 35 |
PART I FINANCIAL INFORMATION
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
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2014 | 2013 | 2014 | 2013 | |||||||||||||
(Unaudited) | ||||||||||||||||
(Amounts in thousands, except per share data) | ||||||||||||||||
Revenues: |
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Natural gas sales |
$ | 228,573 | $ | 234,785 | $ | 500,111 | $ | 436,985 | ||||||||
Oil sales |
67,490 | 26,591 | 122,250 | 50,018 | ||||||||||||
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Total operating revenues |
296,063 | 261,376 | 622,361 | 487,003 | ||||||||||||
Expenses: |
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Lease operating expenses |
22,959 | 17,514 | 43,972 | 36,331 | ||||||||||||
Liquids gathering system operating lease expense |
5,076 | 5,000 | 10,153 | 10,000 | ||||||||||||
Production taxes |
24,594 | 20,006 | 50,525 | 36,561 | ||||||||||||
Gathering fees |
13,449 | 13,834 | 26,157 | 25,718 | ||||||||||||
Transportation charges |
17,273 | 20,649 | 37,848 | 40,958 | ||||||||||||
Depletion, depreciation and amortization |
65,341 | 60,123 | 128,522 | 121,591 | ||||||||||||
General and administrative |
2,158 | 5,876 | 8,503 | 11,837 | ||||||||||||
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Total operating expenses |
150,850 | 143,002 | 305,680 | 282,996 | ||||||||||||
Operating income |
145,213 | 118,374 | 316,681 | 204,007 | ||||||||||||
Other income (expense), net: |
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Interest expense |
(27,294 | ) | (25,238 | ) | (54,362 | ) | (51,002 | ) | ||||||||
(Loss) gain on commodity derivatives |
(15,102 | ) | 22,091 | (60,375 | ) | (22,624 | ) | |||||||||
Deferred gain on sale of liquids gathering system |
2,638 | 2,636 | 5,276 | 5,276 | ||||||||||||
Other (expense) income, net |
50 | 5 | 2 | 13 | ||||||||||||
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Total other expense, net |
(39,708 | ) | (506 | ) | (109,459 | ) | (68,337 | ) | ||||||||
Income before income tax (benefit) provision |
105,505 | 117,868 | 207,222 | 135,670 | ||||||||||||
Income tax (benefit) provision |
(544 | ) | 1,491 | (541 | ) | 2,859 | ||||||||||
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Net income |
$ | 106,049 | $ | 116,377 | $ | 207,763 | $ | 132,811 | ||||||||
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Net income per common share basic |
$ | 0.69 | $ | 0.76 | $ | 1.36 | $ | 0.87 | ||||||||
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Net income per common share fully diluted |
$ | 0.68 | $ | 0.75 | $ | 1.34 | $ | 0.86 | ||||||||
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Weighted average common shares outstanding basic |
153,179 | 152,948 | 153,110 | 152,947 | ||||||||||||
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Weighted average common shares outstanding fully diluted |
155,007 | 154,513 | 154,915 | 154,397 | ||||||||||||
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See accompanying notes to consolidated financial statements.
3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
June 30, 2014 |
December 31, 2013 |
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(Unaudited) | ||||||||
(Amounts in thousands of U.S. dollars, except share data) |
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ASSETS | ||||||||
Current Assets: |
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Cash and cash equivalents |
$ | 5,092 | $ | 10,664 | ||||
Restricted cash |
117 | 119 | ||||||
Oil and gas revenue receivable |
98,325 | 84,095 | ||||||
Joint interest billing and other receivables |
26,139 | 17,725 | ||||||
Derivative assets |
| 1,415 | ||||||
Other current assets |
15,105 | 14,613 | ||||||
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Total current assets |
144,778 | 128,631 | ||||||
Oil and gas properties, net, using the full cost method of accounting: |
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Proven |
2,178,293 | 2,008,538 | ||||||
Unproven properties not being amortized |
399,027 | 413,073 | ||||||
Property, plant and equipment, net |
219,691 | 216,909 | ||||||
Deferred income taxes |
6 | 6 | ||||||
Deferred financing costs and other |
16,338 | 18,162 | ||||||
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Total assets |
$ | 2,958,133 | $ | 2,785,319 | ||||
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LIABILITIES AND SHAREHOLDERS EQUITY | ||||||||
Current liabilities: |
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Accounts payable |
$ | 59,478 | $ | 54,806 | ||||
Accrued liabilities |
85,746 | 79,811 | ||||||
Current portion of long-term debt |
100,000 | | ||||||
Production taxes payable |
46,717 | 40,538 | ||||||
Interest payable |
31,427 | 31,865 | ||||||
Derivative liabilities |
40,007 | 27,291 | ||||||
Capital cost accrual |
134,329 | 173,165 | ||||||
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Total current liabilities |
497,704 | 407,476 | ||||||
Long-term debt |
2,337,000 | 2,470,000 | ||||||
Deferred gain on sale of liquids gathering system |
142,124 | 147,401 | ||||||
Other long-term obligations |
104,830 | 91,932 | ||||||
Commitments and contingencies |
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Shareholders equity: |
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Common stock no par value; authorized unlimited; issued and outstanding 153,215,746 and 152,990,123 at June 30, 2014 and December 31, 2013, respectively |
489,362 | 487,273 | ||||||
Treasury stock |
(37 | ) | (1,961 | ) | ||||
Retained loss |
(612,850 | ) | (816,802 | ) | ||||
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Total shareholders deficit |
(123,525 | ) | (331,490 | ) | ||||
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Total liabilities and shareholders equity |
$ | 2,958,133 | $ | 2,785,319 | ||||
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See accompanying notes to consolidated financial statements.
4
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30, |
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2014 | 2013 | |||||||
(Unaudited) | ||||||||
(Amounts in thousands of U.S. dollars) | ||||||||
Cash provided by (used in): |
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Operating activities: |
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Net income for the period |
$ | 207,763 | $ | 132,811 | ||||
Adjustments to reconcile net income to cash provided by operating activities: |
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Depletion, depreciation and amortization |
128,522 | 121,591 | ||||||
Unrealized loss on commodity derivatives |
14,130 | 2,860 | ||||||
Deferred gain on sale of liquids gathering system |
(5,276 | ) | (5,276 | ) | ||||
Stock compensation |
1,029 | 6,062 | ||||||
Other |
2,123 | 1,074 | ||||||
Net changes in operating assets and liabilities: |
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Restricted cash |
2 | 2 | ||||||
Accounts receivable |
(22,975 | ) | 3,201 | |||||
Other current assets |
(396 | ) | 994 | |||||
Accounts payable |
4,674 | (27,866 | ) | |||||
Accrued liabilities |
7,806 | (12,752 | ) | |||||
Production taxes payable |
6,247 | (8,479 | ) | |||||
Interest payable |
(438 | ) | 240 | |||||
Other long-term obligations |
5,228 | 3,431 | ||||||
Current taxes payable/receivable |
(1,788 | ) | (8,759 | ) | ||||
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Net cash provided by operating activities |
346,651 | 209,134 | ||||||
Investing Activities: |
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Acquisition of oil and gas properties |
(290 | ) | | |||||
Oil and gas property expenditures |
(271,520 | ) | (197,731 | ) | ||||
Gathering system expenditures |
(4,658 | ) | (3,275 | ) | ||||
Change in capital cost accrual |
(38,836 | ) | (51,383 | ) | ||||
Proceeds from sale of oil and gas properties |
| (129 | ) | |||||
Inventory |
322 | (520 | ) | |||||
Purchase of capital assets |
(2,188 | ) | (195 | ) | ||||
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Net cash used in investing activities |
(317,170 | ) | (253,233 | ) | ||||
Financing activities: |
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Borrowings on long-term debt |
458,000 | 498,000 | ||||||
Payments on long-term debt |
(491,000 | ) | (455,000 | ) | ||||
Deferred financing costs |
(164 | ) | | |||||
Repurchased shares/net share settlements |
(2,557 | ) | (5,265 | ) | ||||
Proceeds from exercise of options |
668 | | ||||||
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Net cash (used in) provided by financing activities |
(35,053 | ) | 37,735 | |||||
(Decrease) in cash during the period |
(5,572 | ) | (6,364 | ) | ||||
Cash and cash equivalents, beginning of period |
10,664 | 12,921 | ||||||
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Cash and cash equivalents, end of period |
$ | 5,092 | $ | 6,557 | ||||
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SUPPLEMENTAL INFORMATION: |
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Non-cash investing activities oil and gas properties |
$ | | 12,651 |
See accompanying notes to consolidated financial statements.
5
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All amounts in this Quarterly Report on Form 10-Q are expressed in thousands of U.S. dollars (except per share data) unless otherwise noted).
DESCRIPTION OF THE BUSINESS:
Ultra Petroleum Corp. (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 the Yukon Territory, Canada. The Companys principal business activities are conducted in the Green River Basin of southwest Wyoming and in the north-central Pennsylvania area of the Appalachian Basin. In addition, the Company owns and operates oil-producing properties and undeveloped acreage in the Uinta Basin in east Utah.
1. SIGNIFICANT ACCOUNTING POLICIES:
The accompanying financial statements, other than the balance sheet data as of December 31, 2013, are unaudited and were prepared from the Companys records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (GAAP). Balance sheet data as of December 31, 2013 was derived from the Companys audited financial statements. The Companys management believes that these financial statements include all adjustments necessary for a fair presentation of the Companys financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Companys annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by generally accepted accounting principles and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Companys most recent annual report on Form 10-K.
Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. GAAP. All inter-company transactions and balances have been eliminated upon consolidation.
(a) Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
(b) Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute.
(c) Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life. The gathering system assets, which are downstream of the Companys well pads, are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Companys proved reserves, including production expected from probable and possible reserves, as well as from third parties.
(d) Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (SEC) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (SEC Release No. 33-8995) and
6
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 932, Extractive Activities Oil and Gas (FASB ASC 932). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Companys proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.
Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized.
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (DD&A) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down for the six months ended June 30, 2014 or 2013.
(e) Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (FASB ASC 815). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Income as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 6).
(f) Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that
7
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the more likely than not criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.
(g) Earnings Per Share: Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, 2014 |
June 30, 2013 |
June 30, 2014 |
June 30, 2013 |
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(Share amounts in 000s) | ||||||||||||||||
Net income |
$ | 106,049 | $ | 116,377 | $ | 207,763 | $ | 132,811 | ||||||||
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Weighted average common shares outstanding basic |
153,179 | 152,948 | 153,110 | 152,947 | ||||||||||||
Effect of dilutive instruments |
1,828 | 1,565 | 1,805 | 1,450 | ||||||||||||
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Weighted average common shares outstanding fully diluted |
155,007 | 154,513 | 154,915 | 154,397 | ||||||||||||
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Net income per common share basic |
$ | 0.69 | $ | 0.76 | $ | 1.36 | $ | 0.87 | ||||||||
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Net income per common share fully diluted |
$ | 0.68 | $ | 0.75 | $ | 1.34 | $ | 0.86 | ||||||||
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Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares |
1,196 | 1,332 | 1,707 | 2,014 | ||||||||||||
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(h) Use of Estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(i) Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation Stock Compensation.
(j) Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (FASB ASC 820), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 7 for additional information.
(k) Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset
8
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.
(l) Revenue Recognition: The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. 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 Companys ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Companys share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.
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 imbalances.
(m) 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, as well as on work in process relating to gathering systems.
(n) Capital Cost Accrual: The Company accrues for exploration and development costs and construction of gathering systems in the period incurred, while payment may occur in a subsequent period.
(o) Recent Accounting Pronouncements: In June 2014, the FASB issued Accounting Standards Update (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. ASU No. 2014-09 becomes effective at the beginning of 2017. We are still evaluating the impact of ASU No. 2014-09 on our financial position or results of operations.
9
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
2. OIL AND GAS PROPERTIES AND EQUIPMENT:
June 30, 2014 |
December 31, 2013 |
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Proven Properties: |
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Acquisition, equipment, exploration, drilling and environmental costs |
$ | 8,108,781 | $ | 7,817,374 | ||||
Less: Accumulated depletion, depreciation and amortization(1) |
(5,930,488 | ) | (5,808,836 | ) | ||||
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2,178,293 | 2,008,538 | |||||||
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Unproven Properties: |
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Acquisition and exploration costs not being amortized(1) |
399,027 | 413,073 | ||||||
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Net capitalized costs oil and gas properties |
$ | 2,577,320 | $ | 2,421,611 | ||||
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Property, Plant and Equipment: |
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Gathering Systems(1) |
$ | 297,837 | $ | 294,356 | ||||
Less: Accumulated depreciation |
(107,258 | ) | (105,246 | ) | ||||
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190,579 | 189,110 | |||||||
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Other Property and Equipment |
16,339 | 15,198 | ||||||
Less: Accumulated depreciation |
(10,334 | ) | (9,758 | ) | ||||
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6,005 | 5,440 | |||||||
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Land |
23,107 | 22,359 | ||||||
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Net capitalized costs property, plant and equipment |
$ | 219,691 | $ | 216,909 | ||||
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(1) | For the six months ended June 30, 2014 and 2013, total interest on outstanding debt was $65.3 million and $51.4 million, respectively, of which, $10.9 million and $0.4 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems. |
3. DEBT AND OTHER LONG-TERM OBLIGATIONS:
June 30, 2014 |
December 31, 2013 |
|||||||
Short-term debt: |
||||||||
Senior Notes due March 2015 |
$ | 100,000 | $ | | ||||
Long-term debt and other obligations: |
||||||||
Bank indebtedness |
427,000 | 460,000 | ||||||
Senior Notes |
1,910,000 | 2,010,000 | ||||||
Other long-term obligations |
104,830 | 91,932 | ||||||
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|||||
$ | 2,541,830 | $ | 2,561,932 | |||||
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Ultra Resources, Inc. Bank Indebtedness: The Companys subsidiary, Ultra Resources, Inc. (Ultra Resources, or Borrower), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the Credit Agreement). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With majority (over 50%) lender consent, the term of
10
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
the consenting lenders commitments may be extended for up to two successive one-year periods at the Borrowers request. At June 30, 2014, the Company had $427.0 million in outstanding borrowings and $573.0 million of unused debt capacity under the Credit Agreement.
Loans under the Credit Agreement are unsecured and bear interest, at the Borrowers 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 125 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrowers consolidated leverage ratio (225 basis points per annum as of June 30, 2014). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.
The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Companys debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Companys oil and gas properties to total funded debt of no less than one and one half times to one. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement.
Ultra Resources, Inc. Senior Notes: Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources Senior Notes rank pari passu with the Companys 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 Facility. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes.
Ultra Petroleum Corp. Senior Notes: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (Notes). The Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 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 Notes are not guaranteed by the Companys subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Companys subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the Notes at the following prices expressed as a percentage of principal amount of the Notes: (2015 102.875%; 2016 101.438%; and 2017 and thereafter 100.000%). The Notes are subject to covenants that restrict the Companys 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 Notes contain events of default customary for a senior note financing. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Notes.
Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.
11
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. SHARE BASED COMPENSATION:
Valuation and Expense Information
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Total cost of share-based payment plans |
$ | (1,041 | ) | $ | 4,355 | $ | 1,739 | $ | 8,858 | |||||||
Amounts capitalized in oil and gas properties and equipment |
$ | 435 | $ | 1,302 | $ | 710 | $ | 2,796 | ||||||||
Amounts charged against income, before income tax benefit (provision) |
$ | (1,476 | ) | $ | 3,053 | $ | 1,029 | $ | 6,062 | |||||||
Amount of related income tax (expense) benefit recognized in income before valuation allowance |
$ | (617 | ) | $ | 1,257 | $ | 430 | $ | 2,496 |
Changes in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for the six months ended June 30, 2014 and the year ended December 31, 2013:
Number of Options (000s) |
Weighted Average Exercise Price (US$) |
|||||||||||||||
Balance, December 31, 2012 |
1,357 | $ | 16.97 | to | $ | 98.87 | ||||||||||
|
|
|
|
|
|
|||||||||||
Forfeited |
(110 | ) | $ | 25.68 | to | $ | 75.18 | |||||||||
Exercised |
(1 | ) | $ | 16.97 | to | $ | 16.97 | |||||||||
|
|
|
|
|
|
|||||||||||
Balance, December 31, 2013 |
1,246 | $ | 16.97 | to | $ | 98.87 | ||||||||||
|
|
|
|
|
|
|||||||||||
Forfeited |
(1 | ) | $ | 63.05 | to | $ | 63.05 | |||||||||
Exercised |
(39 | ) | $ | 16.97 | to | $ | 16.97 | |||||||||
|
|
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|
|
|
|||||||||||
Balance, June 30, 2014 |
1,206 | $ | 25.68 | to | $ | 98.87 | ||||||||||
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Performance Share Plans:
Long Term Incentive Plans. The Company offers a Long Term Incentive Plan (LTIP) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years. In 2012, 2013 and 2014, the Compensation Committee (the Committee) approved an award consisting of performance-based restricted stock units to be awarded to each participant.
For each LTIP award, the Committee establishes performance measures at the beginning of each three-year performance period. Under each LTIP, the Committee also establishes a percentage of base salary for each participant which is multiplied by the participants base salary at the beginning of the performance period and individual performance level to derive a Long Term Incentive Value as a target value. This target value corresponds to the number of shares of the Companys common stock the participant is eligible to receive if the participant is employed by the Company through the date the award vests and if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event the Companys actual performance is below or above the target levels. For the LTIP awards in 2012,
12
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth. For the LTIP awards in 2013 and 2014, the Committee established the following performance measures: return on capital employed, debt level, reserve replacement ratio, and total shareholder return (officers only).
For the six months ended June 30, 2014, the Company recognized $2.5 million in pre-tax compensation expense related to the 2012, 2013 and 2014 LTIP awards of restricted stock units as compared to $4.6 million during the six months ended June 30, 2013 related to the 2011, 2012 and 2013 LTIP awards of restricted stock units. The amounts recognized during the six months ended June 30, 2014 assume that maximum performance objectives are attained under each of the LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at June 30, 2014, for each of the three year performance periods is expected to be approximately $10.2 million, $12.4 million, and $13.2 million related to the 2012, 2013 and 2014 LTIP awards of restricted stock units, respectively. The 2011 LTIP award of restricted stock units was paid in shares of the Companys stock to employees during the first quarter of 2014 and totaled $8.4 million (106,437 net shares).
5. INCOME TAXES:
The Companys overall effective tax rate on pre-tax income was different than the statutory rate of 35% due primarily to valuation allowances, state income taxes and other permanent differences.
The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of June 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.
6. DERIVATIVE FINANCIAL INSTRUMENTS:
Objectives and Strategy: The Companys major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Companys natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.
The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Companys forward cash flows supporting the Companys capital investment program.
The Companys hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval.
Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivatives fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.
Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are
13
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
recorded as current income or expense in the Consolidated Statements of Income. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.
Commodity Derivative Contracts: At June 30, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.
Fixed price swaps: The Company receives the fixed price for the contract and pays the variable price to the counterparty.
Basis Swaps: Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Natural Gas: | ||||||||||||||||||||
Type |
Commodity Reference Price |
Remaining Contract Period |
Volume - MMBTU/ Day |
Average Price/ MMBTU |
Average Basis Differential/ MMBTU |
Fair Value - June 30, 2014 |
||||||||||||||
(Liability) | ||||||||||||||||||||
Fixed price swap |
NYMEX-Henry Hub | July - Oct 2014 | 480,000 | $ | 3.90 | | $ | (31,754 | ) | |||||||||||
Fixed price swap |
NYMEX-Henry Hub | Nov - Dec 2014 | 85,000 | $ | 4.35 | | $ | (803 | ) | |||||||||||
Basis swap |
Rocky Mtns (NWPL) | July 2014 | 30,000 | | -$ | 0.105 | $ | (107 | ) | |||||||||||
Crude Oil: | ||||||||||||||||||||
Type |
Commodity Reference Price |
Remaining |
Volume - Bbls/Day |
Average Price/Bbl |
Average
Basis Differential /Bbl |
Fair Value - June 30, 2014 |
||||||||||||||
(Liability) | ||||||||||||||||||||
Fixed price swap |
NYMEX-WTI | July - Dec 2014 | 4,000 | $ | 93.19 | | $ | (7,343 | ) |
14
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following table summarizes the pre-tax realized and unrealized (loss) gain the Company recognized related to its derivative instruments in the Consolidated Statements of Income for the periods ended June 30, 2014 and 2013:
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
Commodity Derivatives: | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Realized loss on commodity derivatives-natural gas(1) |
$ | (33,729 | ) | $ | (19,764 | ) | $ | (40,843 | ) | $ | (19,764 | ) | ||||
Realized loss on commodity derivatives-crude oil(1) |
(3,562 | ) | | (5,402 | ) | | ||||||||||
Unrealized gain (loss) on commodity derivatives(1) |
22,189 | 41,855 | (14,130 | ) | (2,860 | ) | ||||||||||
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|
|
|
|
|
|
|
|||||||||
Total (loss) gain on commodity derivatives |
$ | (15,102 | ) | $ | 22,091 | $ | (60,375 | ) | $ | (22,624 | ) | |||||
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(1) | Included in (loss) gain on commodity derivatives in the Consolidated Statements of Income. |
The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Companys derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.
7. FAIR VALUE MEASUREMENTS:
As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:
Level 1: |
Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. | |
Level 2: |
Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps. | |
Level 3: |
Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. |
The valuation assumptions utilized to measure the fair value of the Companys commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).
15
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following table presents for each hierarchy level the Companys assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of June 30, 2014. The Company has no derivative instruments which qualify for cash flow hedge accounting.
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Liabilities: |
||||||||||||||||
Current derivative liability |
$ | | $ | 40,007 | $ | | $ | 40,007 |
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
Fair Value of Financial Instruments
The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Companys debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Companys financial position, results of operations or cash flows.
June 30, 2014 | December 31, 2013 | |||||||||||||||
Carrying Amount |
Estimated Fair Value |
Carrying Amount |
Estimated Fair Value |
|||||||||||||
5.45% Notes due March 2015, issued 2008 |
$ | 100,000 | $ | 103,950 | $ | 100,000 | $ | 105,913 | ||||||||
7.31% Notes due March 2016, issued 2009 |
62,000 | 68,371 | 62,000 | 70,228 | ||||||||||||
4.98% Notes due January 2017, issued 2010 |
116,000 | 123,818 | 116,000 | 126,342 | ||||||||||||
5.92% Notes due March 2018, issued 2008 |
200,000 | 222,247 | 200,000 | 226,127 | ||||||||||||
5.75% Notes due December 2018, issued 2013 |
450,000 | 463,634 | 450,000 | 466,946 | ||||||||||||
7.77% Notes due March 2019, issued 2009 |
173,000 | 208,034 | 173,000 | 211,877 | ||||||||||||
5.50% Notes due January 2020, issued 2010 |
207,000 | 226,818 | 207,000 | 229,068 | ||||||||||||
4.51% Notes due October 2020, issued 2010 |
315,000 | 323,556 | 315,000 | 323,732 | ||||||||||||
5.60% Notes due January 2022, issued 2010 |
87,000 | 95,464 | 87,000 | 95,736 | ||||||||||||
4.66% Notes due October 2022, issued 2010 |
35,000 | 35,703 | 35,000 | 35,494 | ||||||||||||
5.85% Notes due January 2025, issued 2010 |
90,000 | 99,815 | 90,000 | 99,142 | ||||||||||||
4.91% Notes due October 2025, issued 2010 |
175,000 | 178,089 | 175,000 | 175,744 | ||||||||||||
Credit Facility due October 2016 |
427,000 | 427,000 | 460,000 | 460,000 | ||||||||||||
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$ | 2,437,000 | $ | 2,576,499 | $ | 2,470,000 | $ | 2,626,349 | |||||||||
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16
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
8. LEGAL PROCEEDINGS:
The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Companys financial position or results of operations.
9. SUBSEQUENT EVENTS:
The Company has evaluated the period subsequent to June 30, 2014 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.
17
ITEM 2 MANAGEMENTS 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 Companys 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 and is in the early exploration and development stages for oil reserves in the Uinta Basin in Utah and 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 Companys 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 Companys 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 Companys revenues coming from gas sales from wells located in the Appalachian Basin in Pennsylvania and oil sales from its properties in the Uinta Basin in Utah.
The prices of oil and natural gas are critical factors to the Companys business. The prices of oil and natural gas have historically been volatile, and this volatility could be detrimental to the Companys 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).
During the quarter ended June 30, 2014, the average price realization for the Companys natural gas was $3.61 per Mcf, including realized gains and losses on commodity derivatives compared with $3.80 per Mcf during the quarter ended June 30, 2013. The Companys average price realization for natural gas was $4.23 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $4.15 per Mcf during the second quarter of 2013.
During the quarter ended June 30, 2014, the average price realization for the Companys oil was $84.24 per barrel, including realized gains and losses on commodity derivatives compared with $88.90 per barrel during the quarter ended June 30, 2013. The Companys average price realization for oil was $88.94 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $88.90 per barrel during the second quarter of 2013.
Critical Accounting Policies
The discussion and analysis of the Companys 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
18
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 the Companys financial statements which the Company believes 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 Income as an unrealized gain or loss on commodity derivatives.
Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (FASB ASC 820). Under 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. The valuation assumptions utilized to measure the fair value of the Companys commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance with the requirements of FASB ASC 820 and the Company aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by FASB ASC 820. The balance of net unrealized gains and losses recognized for the Companys energy-related derivative instruments at June 30, 2014 is summarized in the following table based on the inputs used to determine fair value:
Level 1(a) | Level 2(b) | Level 3(c) | Total | |||||||||||||
(Amounts in 000s) | ||||||||||||||||
Liabilities: |
||||||||||||||||
Current derivative liability |
$ | | $ | 40,007 | $ | | $ | 40,007 |
(a) | Values represent observable unadjusted quoted prices for traded instruments in active markets. |
(b) | Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1. |
(c) | Values with a significant amount of inputs that are not observable for the instrument. |
Asset Retirement Obligation. The Companys 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 discounted 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, estimated probabilities, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent 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
19
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 six months ended June 30, 2014 and 2013 was $1.0 million and $6.1 million, respectively. See Note 4 for additional information.
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 Companys 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, 2014 or 2013.
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, as well as on work in process relating to gathering systems that are not currently in service (See Note 2).
Revenue Recognition. The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of
20
oil and natural gas. 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 Companys ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.
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 imbalances.
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 substantially all of its net deferred tax asset balance as of June 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.
Recent accounting pronouncements. In June 2014, the FASB issued Accounting Standards Update (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. ASU No. 2014-09 becomes effective at the beginning of 2017. We are still evaluating the impact of ASU No. 2014-09 on our financial position or results of operations.
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.
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RESULTS OF OPERATIONS:
For the Three Months Ended June 30, 2014 |
% Variance F/(U) |
For the Six Months Ended June 30, 2014 |
% Variance F/(U) |
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2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
(Amounts in thousands, except per unit data) | ||||||||||||||||||||||||
Production, Commodity Prices and Revenues: |
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Production: |
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Natural gas (Mcf) |
53,993 | 56,624 | -5 | % | 107,285 | 114,351 | -6 | % | ||||||||||||||||
Crude oil and condensate (Bbls) |
759 | 299 | 154 | % | 1,417 | 567 | 150 | % | ||||||||||||||||
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Total production (Mcfe) |
58,546 | 58,419 | 0 | % | 115,787 | 117,756 | -2 | % | ||||||||||||||||
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Commodity Prices: |
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Natural gas ($/Mcf, including realized hedges) |
$ | 3.61 | $ | 3.80 | -5 | % | $ | 4.28 | $ | 3.65 | 17 | % | ||||||||||||
Natural gas ($/Mcf, excluding hedges) |
$ | 4.23 | $ | 4.15 | 2 | % | $ | 4.66 | $ | 3.82 | 22 | % | ||||||||||||
Oil and condensate ($/Bbl, incl realized hedges) |
$ | 84.24 | $ | 88.90 | -5 | % | $ | 82.47 | $ | 88.16 | -6 | % | ||||||||||||
Oil and condensate ($/Bbl, excl realized hedges) |
$ | 88.94 | $ | 88.90 | 0 | % | $ | 86.28 | $ | 88.16 | -2 | % | ||||||||||||
Revenues: |
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Natural gas sales |
$ | 228,573 | $ | 234,785 | -3 | % | $ | 500,111 | $ | 436,985 | 14 | % | ||||||||||||
Oil sales |
$ | 67,490 | $ | 26,591 | 154 | % | $ | 122,250 | $ | 50,018 | 144 | % | ||||||||||||
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Total operating revenues |
$ | 296,063 | $ | 261,376 | 13 | % | $ | 622,361 | $ | 487,003 | 28 | % | ||||||||||||
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Derivatives: |
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Realized (loss) on commodity derviatives-natural gas |
$ | (33,729 | ) | $ | (19,764 | ) | -71 | % | $ | (40,843 | ) | $ | (19,764 | ) | -107 | % | ||||||||
Realized (loss) on commodity derviatives-crude oil |
$ | (3,562 | ) | $ | | n/a | $ | (5,402 | ) | $ | | n/a | ||||||||||||
Unrealized gain (loss) on commodity derivatives |
$ | 22,189 | $ | 41,855 | 47 | % | $ | (14,130 | ) | $ | (2,860 | ) | -394 | % | ||||||||||
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Total (loss) gain on commodity derivatives |
$ | (15,102 | ) | $ | 22,091 | 168 | % | $ | (60,375 | ) | $ | (22,624 | ) | -167 | % | |||||||||
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Operating Costs and Expenses: |
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Lease operating expenses |
$ | 22,959 | $ | 17,514 | -31 | % | $ | 43,972 | $ | 36,331 | -21 | % | ||||||||||||
Liquids gathering system operating lease expense |
$ | 5,076 | $ | 5,000 | -2 | % | $ | 10,153 | $ | 10,000 | -2 | % | ||||||||||||
Production taxes |
$ | 24,594 | $ | 20,006 | -23 | % | $ | 50,525 | $ | 36,561 | -38 | % | ||||||||||||
Gathering fees |
$ | 13,449 | $ | 13,834 | 3 | % | $ | 26,157 | $ | 25,718 | -2 | % | ||||||||||||
Transportation charges |
$ | 17,273 | $ | 20,649 | 16 | % | $ | 37,848 | $ | 40,958 | 8 | % | ||||||||||||
Depletion, depreciation and amortization |
$ | 65,341 | $ | 60,123 | -9 | % | $ | 128,522 | $ | 121,591 | -6 | % | ||||||||||||
General and administrative expenses |
$ | 2,158 | $ | 5,876 | 63 | % | $ | 8,503 | $ | 11,837 | 28 | % | ||||||||||||
Per Unit Costs and Expenses ($/Mcfe): |
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Lease operating expenses |
$ | 0.39 | $ | 0.30 | -30 | % | $ | 0.38 | $ | 0.31 | -23 | % | ||||||||||||
Liquids gathering system operating lease expense |
$ | 0.09 | $ | 0.09 | 0 | % | $ | 0.09 | $ | 0.08 | -13 | % | ||||||||||||
Production taxes |
$ | 0.42 | $ | 0.34 | -24 | % | $ | 0.44 | $ | 0.31 | -42 | % | ||||||||||||
Gathering fees |
$ | 0.23 | $ | 0.24 | 4 | % | $ | 0.23 | $ | 0.22 | -5 | % | ||||||||||||
Transportation charges |
$ | 0.30 | $ | 0.35 | 14 | % | $ | 0.33 | $ | 0.35 | 6 | % | ||||||||||||
Depletion, depreciation and amortization |
$ | 1.12 | $ | 1.03 | -9 | % | $ | 1.11 | $ | 1.03 | -8 | % | ||||||||||||
General and administrative expenses |
$ | 0.04 | $ | 0.10 | 60 | % | $ | 0.07 | $ | 0.10 | 30 | % |
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Quarter Ended June 30, 2014 vs. Quarter Ended June 30, 2013
Production, Commodity Derivatives and Revenues:
Production. During the quarter ended June 30, 2014, production remained flat on a gas equivalent basis at 58.5 Bcfe compared to 58.4 Bcfe for the same quarter in 2013. However, on an Mcfe basis, oil production increased from 3.1% of total production during the second quarter of 2013 to 7.8% of total production during the second quarter of 2014.
Commodity Prices Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 5% to $3.61 per Mcf in the second quarter of 2014 as compared to $3.80 per Mcf for the same quarter of 2013. During the three months ended June 30, 2014, the Companys average price for natural gas excluding realized gains and losses on commodity derivatives was $4.23 per Mcf as compared to $4.15 per Mcf for the same period in 2013.
Commodity Prices Oil. During the quarter ended June 30, 2014, the average price realization for the Companys oil was $84.24 per barrel, including realized gains and losses on commodity derivatives compared with $88.90 per barrel during the quarter ended June 30, 2013. The Companys average price realization for oil was $88.94 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $88.90 per barrel during the second quarter of 2013.
Revenues. Oil production from the recently acquired assets in Utah along with the increase in average natural gas prices, excluding the gains and losses on commodity derivatives, resulted in revenues increasing to $296.1 million for the quarter ended June 30, 2014 as compared to $261.4 million in for the same period in 2013.
Operating Costs and Expenses:
Lease Operating Expense. Lease operating expense (LOE) increased to $23.0 million during the second quarter of 2014 compared to $17.5 million during the same period in 2013 largely related to the recently acquired assets in Utah. On a unit of production basis, LOE costs increased to $0.39 per Mcfe during the second quarter of 2014 compared to $0.30 per Mcfe during the same period in 2013 as a result of increased costs associated with the Utah acquisition during the period ended June 30, 2014.
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 Companys sale leaseback transaction was treated as a normal leaseback under the provisions of FASB ASC Topic 840, Leases (FASB ASC Topic 840) and qualified for sales recognition. The lease is classified as an operating lease. For the three months ended June 30, 2014, the Company recognized operating lease expense associated with the Lease Agreement of $5.1 million, or $0.09 per Mcfe as compared to $5.0 million, or $0.09 per Mcfe for the same period in 2013.
Production Taxes. During the three months ended June 30, 2014, production taxes were $24.6 million compared to $20.0 million during the same period in 2013, or $0.42 per Mcfe compared to $0.34 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.3% of revenues for the quarter ended June 30, 2014 and 7.7% of revenues for the same period in 2013. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives during the quarter ended June 30, 2014 as compared to the same period in 2013.
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Gathering Fees. Gathering fees remained relatively flat at $13.4 million for the three months ended June 30, 2014 compared to $13.8 million during the same period in 2013. On a per unit basis, gathering fees decreased slightly to $0.23 per Mcfe for the three months ended June 30, 2014 as compared to $0.24 per Mcfe during the same period in 2013.
Transportation Charges. The Company incurred firm transportation charges totaling $17.3 million for the quarter ended June 30, 2014 as compared to $20.6 million for the same period in 2013 in association with Rockies Express Pipeline (REX) transportation charges. Transportation charges decreased primarily due to a refund during the quarter for over collection of tariffs related to Fuel, Loss and Unaccounted-for-Gas applicable to transport on REXs system. On a per unit basis, transportation charges decreased to $0.30 per Mcfe (on total company volumes) for the three months ended June 30, 2014 as compared to $0.35 per Mcfe (on total company volumes) for the same period in 2013.
Depletion, Depreciation and Amortization. DD&A expenses increased to $65.3 million during the three months ended June 30, 2014 from $60.1 million for the same period in 2013, attributable to a higher depletion rate primarily related to the Utah acquisition. On a unit of production basis, DD&A increased to $1.12 per Mcfe for the quarter ended June 30, 2014 from $1.03 per Mcfe for the quarter ended June 30, 2013.
General and Administrative Expenses. General and administrative expenses decreased to $2.2 million for the quarter ended June 30, 2014 compared to $5.9 million for the same period in 2013 primarily related to decreased incentive compensation expense. On a per unit basis, general and administrative expenses decreased to $0.04 per Mcfe for the quarter ended June 30, 2014 compared to $0.10 per Mcfe for the quarter ended June 30, 2013.
Other Income and Expenses:
Interest expense. Interest expense increased to $27.3 million during the quarter ended June 30, 2014 compared to $25.2 million during the same period in 2013 primarily as a result of higher average borrowings outstanding and partially offset by increased amounts of capitalized interest for the quarter ended June 30, 2014 as compared to the same period in 2013. (See Note 2).
Deferred Gain on Sale of Liquids Gathering System. During the quarters ended June 30, 2014 and 2013, 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:
(Loss) gain on Commodity Derivatives. During the quarter ended June 30, 2014, the Company recognized a loss of $15.1 million compared with a gain of $22.1 million during the same period in 2013 related to commodity derivatives. Of this total, the Company recognized $37.3 million of realized loss on commodity derivatives during the quarter ended June 30, 2014 compared with $19.8 million of realized loss on commodity derivatives during the three months ended June 30, 2013. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Companys derivative contracts. This amount also includes an unrealized gain on commodity derivatives of $22.2 million during the quarter ended June 30, 2014 as compared to $41.9 million in unrealized gain on commodity derivatives during the quarter ended June 30, 2013. 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.
Income from Continuing Operations:
Pretax Income. The Company recognized income before income taxes of $105.5 million for the quarter ended June 30, 2014 compared with income before income taxes of $117.9 million for the same period in 2013. The decrease in earnings is primarily due to the loss on commodity derivatives and offset by increased revenues
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as a result of increased oil production during the three months ended June 30, 2014 as compared to the same period in 2013.
Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of June 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.
Net Income. For the three months ended June 30, 2014, the Company recognized net income of $106.0 million or $0.68 per diluted share as compared with net income of $116.4 million or $0.75 per diluted share for the same period in 2013. The decrease is primarily due to the loss on commodity derivatives and offset by increased revenues as a result of increased oil production during the three months ended June 30, 2014 as compared to the same period in 2013.
Six Months Ended June 30, 2014 vs. Six Ended June 30, 2013
Production, Commodity Derivatives and Revenues:
Production. During the six months ended June 30, 2014, production decreased on a gas equivalent basis to 115.8 Bcfe compared to 117.8 Bcfe for the same period in 2013 as a result of decreased capital spending during 2013. However, on an Mcfe basis, oil production increased from 2.9% of total production during the six months ended June 30, 2013 to 7.3% of total production during the six months ended June 30, 2014.
Commodity Prices Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 17% to $4.28 per Mcf during the six months ended June 30, 2014 as compared to $3.65 per Mcf during 2013. During the six months ended June 30, 2014, the Companys average price for natural gas excluding realized gains and losses on commodity derivatives was $4.66 per Mcf as compared to $3.82 per Mcf for the same period in 2013.
Commodity Prices Oil. During the six months ended June 30, 2014, the average price realization for the Companys oil was $82.47 per barrel, including realized gains and losses on commodity derivatives compared with $88.16 per barrel during the six months ended June 30, 2013. The Companys average price realization for oil was $86.28 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $88.16 per barrel during the six months ended June 30, 2013.
Revenues. Oil production from the recently acquired assets in Utah along with the increase in average natural gas prices, excluding the gains and losses on commodity derivatives, partially offset by the decrease in natural gas production resulted in revenues increasing to $622.4 million for the six months ended June 30, 2014 as compared to $487.0 million in for the same period in 2013.
Operating Costs and Expenses:
Lease Operating Expense. LOE increased to $44.0 million during the six months ended June 30, 2014 compared to $36.3 million during the same period in 2013 largely related to the recently acquired assets in Utah. On a unit of production basis, LOE costs increased to $0.38 per Mcfe during the six months ended June 30, 2014 compared to $0.31 per Mcfe during the same period in 2013 as a result of decreased production volumes and increased costs related to the recently acquired assets in Utah during the period ended June 30, 2014.
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 Companys
25
sale leaseback transaction was treated as a normal leaseback under the provisions of FASB ASC Topic 840, Leases (FASB ASC Topic 840) and qualified for sales recognition. The lease is classified as an operating lease. For the six months ended June 30, 2014, the Company recognized operating lease expense associated with the Lease Agreement of $10.2 million, or $0.09 per Mcfe as compared to $10.0 million, or $0.08 per Mcfe for the same period in 2013.
Production Taxes. During the six months ended June 30, 2014, production taxes were $50.5 million compared to $36.6 million during the same period in 2013, or $0.44 per Mcfe compared to $0.31 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.1% of revenues for the six months ended June 30, 2014 and 7.5% of revenues for the same period in 2013. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives during the six months ended June 30, 2014 as compared to the same period in 2013.
Gathering Fees. Gathering fees increased slightly to $26.2 million for the six months ended June 30, 2014 compared to $25.7 million during the same period in 2013. On a per unit basis, gathering fees increased slightly to $0.23 per Mcfe for the six months ended June 30, 2014 as compared to $0.22 per Mcfe during the same period in 2013.
Transportation Charges. The Company incurred firm transportation charges totaling $37.8 million for the six months ended June 30, 2014 as compared to $41.0 million for the same period in 2013 in association with Rockies Express Pipeline (REX) transportation charges. Transportation charges decreased due to a refund during the second quarter for over collection of tariffs related to Fuel, Loss and Unaccounted-for-Gas applicable to transport on REXs system. On a per unit basis, transportation charges decreased to $0.33 per Mcfe (on total company volumes) for the six months ended June 30, 2014 as compared to $0.35 per Mcfe (on total company volumes) for the same period in 2013.
Depletion, Depreciation and Amortization. DD&A expenses increased to $128.5 million during the six months ended June 30, 2014 from $121.6 million for the same period in 2013, attributable to a higher depletion rate primarily related to the Utah acquisition. On a unit of production basis, DD&A increased to $1.11 per Mcfe for the six months ended June 30, 2014 from $1.03 per Mcfe for the six months ended June 30, 2013.
General and Administrative Expenses. General and administrative expenses decreased to $8.5 million for the six months ended June 30, 2014 compared to $11.8 million for the same period in 2013 primarily due to decreased incentive compensation expense. On a per unit basis, general and administrative expenses decreased to $0.07 per Mcfe for the six months ended June 30, 2014 compared to $0.10 per Mcfe for the six months ended June 30, 2013.
Other Income and Expenses:
Interest expense. Interest expense increased to $54.4 million during the six months ended June 30, 2014 compared to $51.0 million during the same period in 2013 primarily as a result of higher average borrowings outstanding and partially offset by increased amounts of capitalized interest for the six months ended June 30, 2014 as compared to the same period in 2013. (See Note 2).
Deferred Gain on Sale of Liquids Gathering System. During the six months ended June 30, 2014 and 2013, the Company recognized $5.3 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.
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Commodity Derivatives:
(Loss) on Commodity Derivatives. During the six months ended June 30, 2014, the Company recognized a loss of $60.4 million compared with a loss of $22.6 million during the same period in 2013 related to commodity derivatives. Of this total, the Company recognized $46.2 million of realized loss on commodity derivatives during the six months ended June 30, 2014 compared with $19.8 million of realized loss on commodity derivatives during six months ended June 30, 2013. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Companys derivative contracts. This amount also includes an unrealized loss on commodity derivatives of $14.1 million during the six months ended June 30, 2014 as compared to $2.9 million in unrealized loss on commodity derivatives during the six months ended June 30, 2013. 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.
Income from Continuing Operations:
Pretax Income. The Company recognized income before income taxes of $207.2 million for the six months ended June 30, 2014 compared with income before income taxes of $135.7 million for the same period in 2013. The increase in earnings is largely due to increased revenues as a result of increased natural gas price realizations and increased oil production during the six months ended June 30, 2014 as compared to the same period in 2013.
Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of June 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.
Net Income. For the six months ended June 30, 2014, the Company recognized net income of $207.8 million or $1.34 per diluted share as compared with net income of $132.8 million or $0.86 per diluted share for the same period in 2013. The increase is largely due to increased revenues as a result of increased natural gas price realizations and increased oil production during the six months ended June 30, 2014 as compared to the same period in 2013.
LIQUIDITY AND CAPITAL RESOURCES
During the six month period ended June 30, 2014, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. During this period, the Company participated in 115 gross (83.0 net) wells that were drilled to total depth and cased. For the six month period ended June 30, 2014, total capital expenditures were $276.2 million ($271.5 million related to oil and gas exploration and development expenditures and $4.7 million related to gathering system expenditures).
At June 30, 2014, the Company reported a cash position of $5.1 million compared to $6.6 million at June 30, 2013. Working capital deficit at June 30, 2014 was $352.9 million compared to working capital deficit of $266.6 million at June 30, 2013. At June 30, 2014, the Company had $427.0 million in outstanding borrowings and $573.0 million of available borrowing capacity under the Credit Agreement. In addition, the Company had $2.01 billion outstanding in senior notes (See Note 3). Other long-term obligations of $104.8 million at June 30, 2014 were comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.
The Companys cash provided by operating activities, along with availability under the senior revolving credit facility (see Note 3), are projected to be sufficient to meet the Companys obligations and to fund its budgeted capital investment program for 2014, which is currently projected to be approximately $560.0 million.
Ultra Resources, Inc. Bank Indebtedness: The Companys subsidiary, Ultra Resources, Inc. (Ultra Resources, or Borrower), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the Credit Agreement). The Credit Agreement provides an initial loan
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commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With majority (over 50%) lender consent, the term of the consenting lenders commitments may be extended for up to two successive one-year periods at the Borrowers request. At June 30, 2014, the Company had $427.0 million in outstanding borrowings and $573.0 million of unused debt capacity under the Credit Agreement.
Loans under the Credit Agreement are unsecured and bear interest, at the Borrowers 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 125 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrowers consolidated leverage ratio (225 basis points per annum as of June 30, 2014). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.
The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Companys debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Companys oil and gas properties to total funded debt of no less than one and one half times to one. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement.
Ultra Resources, Inc. Senior Notes: Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources Senior Notes rank pari passu with the Companys 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 Facility. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes. (See Note 3).
Ultra Petroleum Corp. Senior Notes: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (Notes). The Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 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 Notes are not guaranteed by the Companys subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Companys subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the Notes at the following prices expressed as a percentage of principal amount of the Notes: (2015 102.875%; 2016 101.438%; and 2017 and thereafter 100.000%). The Notes are subject to covenants that restrict the Companys 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 Notes contain events of default customary for a senior note financing. At June 30, 2014, the Company was in compliance with all of its debt covenants under the Notes.
Operating Activities. During the six months ended June 30, 2014, net cash provided by operating activities was $346.7 million, a 66% increase from $209.1 million for the same period in 2013. The increase in net cash provided by operating activities is largely attributable to increased revenues as a result of increased natural gas price realizations and increased oil production during the six months ended June 30, 2014 as compared to the same period in 2013.
Investing Activities. During the six months ended June 30, 2014, net cash used in investing activities was $317.2 million as compared to $253.2 million for the same period in 2013. The increase in net cash used in investing activities is largely related to increased capital investments associated with the Companys drilling activities in 2014 as compared to 2013.
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Financing Activities. During the six months ended June 30, 2014, net cash used in financing activities was $35.1 million as compared to cash provided by financing activities of $37.7 million for the same period in 2013. The change in net cash used in financing activities is primarily due to decreased net borrowings during the six months ended June 30, 2014 as compared to 2013.
OFF BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of June 30, 2014.
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 Managements Discussion and Analysis of Financial Condition and Results of Operations regarding the Companys financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Companys 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 Companys 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 Companys annual report on Form 10-K for the year ended December 31, 2013 for additional risks related to the Companys business.
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Objectives and Strategy: The Companys major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Companys natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.
The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Companys forward cash flows supporting the Companys capital investment program.
The Companys hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval.
Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivatives fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.
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Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Income. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.
Commodity Derivative Contracts: At June 30, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.
Fixed price swaps: The Company receives the fixed price for the contract and pays the variable price to the counterparty.
Basis Swaps: Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Natural Gas: | ||||||||||||||||||||
Type |
Commodity Reference Price |
Remaining Contract Period |
Volume - MMBTU/ Day |
Average Price/ MMBTU |
Average Basis Differential/ MMBTU |
Fair Value - June 30, 2014 |
||||||||||||||
(000s) (Liability) |
||||||||||||||||||||
Fixed price swap |
NYMEX-Henry Hub | July - Oct 2014 | 480,000 | $ | 3.90 | | $ | (31,754 | ) | |||||||||||
Fixed price swap |
NYMEX-Henry Hub | Nov - Dec 2014 | 85,000 | $ | 4.35 | | $ | (803 | ) | |||||||||||
Basis swap |
Rocky Mtns (NWPL) | July 2014 | 30,000 | | -$ | 0.105 | $ | (107 | ) | |||||||||||
Crude Oil: | ||||||||||||||||||||
Type |
Commodity Reference Price |
Remaining Contract Period |
Volume - Bbls/Day |
Average Price/Bbl |
Average Basis Differential/ Bbl |
Fair Value - June 30, 2014 |
||||||||||||||
(000s) (Liability) |
||||||||||||||||||||
Fixed price swap |
NYMEX-WTI | July - Dec 2014 | 4,000 | $ | 93.19 | | $ | (7,343 | ) |
The following table summarizes the pre-tax realized and unrealized (loss) gain the Company recognized related to its derivative instruments in the Consolidated Statements of Income for the periods ended June 30, 2014 and 2013:
For the Three Months Ended June 30, |
For the Six Months Ended June 30, |
|||||||||||||||
Commodity Derivatives (000s): | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Realized loss on commodity derivatives-natural gas(1) |
$ | (33,729 | ) | $ | (19,764 | ) | $ | (40,843 | ) | $ | (19,764 | ) | ||||
Realized loss on commodity derivatives-crude oil(1) |
(3,562 | ) | | (5,402 | ) | | ||||||||||
Unrealized gain (loss) on commodity derivatives(1) |
22,189 | 41,855 | (14,130 | ) | (2,860 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total (loss) gain on commodity derivatives |
$ | (15,102 | ) | $ | 22,091 | $ | (60,375 | ) | $ | (22,624 | ) | |||||
|
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|
|
|
|
|
|
(1) | Included in (loss) gain on commodity derivatives in the Consolidated Statements of Income. |
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The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Companys derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.
ITEM 4 CONTROLS AND PROCEDURES
(a) | Evaluation of Disclosure Controls and Procedures |
The Company has performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act). The Companys disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Companys management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SECs rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Companys management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Companys disclosure controls and procedures were effective as of June 30, 2014. There were no changes in the Companys internal control over financial reporting during the six months ended June 30, 2014 that have materially affected or are reasonably likely to affect, the Companys internal control over financial reporting.
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The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Companys financial position, or results of operations.
There have been no material changes with respect to the risk factors disclosed in the Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2013.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
None.
None.
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(a) Exhibits
3.1 | Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
3.2 | By-Laws of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
3.3 | Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Companys Report on Form 10-K/A for the period ended December 31, 2005.) | |
4.1 | Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1* | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2* | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101.INS* | XBRL Instance Document. | |
101.SCH* | XBRL Taxonomy Extension Schema Document. | |
101.CAL* | XBRL Taxonomy Calculation Linkbase Document. | |
101.LAB* | XBRL Label Linkbase Document. | |
101.PRE* | XBRL Presentation Linkbase Document. | |
101.DEF* | XBRL Taxonomy Extension Definition. |
* | Filed herewith. |
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ULTRA PETROLEUM CORP. | ||
By: | /s/ Michael D. Watford |
Name: | Michael D. Watford | |||
Title: | Chairman, President and | |||
Chief Executive Officer |
Date: July 31, 2014
By: | /s/ Marshall D. Smith |
Name: |
Marshall D. Smith | |||
Title: |
Senior Vice President and | |||
Chief Financial Officer |
Date: July 31, 2014
34
3.1 | Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
3.2 | By-Laws of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
3.3 | Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Companys Report on Form 10-K/A for the period ended December 31, 2005.) | |
4.1 | Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Companys Quarterly Report on Form 10Q for the period ended June 30, 2001.) | |
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1* | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2* | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101.INS* | XBRL Instance Document. | |
101.SCH* | XBRL Taxonomy Extension Schema Document. | |
101.CAL* | XBRL Taxonomy Calculation Linkbase Document. | |
101.LAB* | XBRL Label Linkbase Document. | |
101.PRE* | XBRL Presentation Linkbase Document. | |
101.DEF* | XBRL Taxonomy Extension Definition. |
* | Filed herewith. |
35