e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2008
or
|
|
|
o |
|
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 0-29370
ULTRA PETROLEUM CORP.
(Exact name of registrant as specified in its charter)
|
|
|
Yukon Territory, Canada
|
|
N/A |
(State or other jurisdiction of
|
|
(I.R.S. employer |
incorporation or organization)
|
|
identification number) |
|
|
|
363 North Sam Houston Parkway,
Suite 1200, Houston, Texas
(Address of principal executive offices)
|
|
77060
(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 þ NO o
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 þ |
|
Accelerated filer o |
|
Non-accelerated filer o
(Do not check if a smaller reporting company) |
|
Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). YES o NO þ
The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of
July 31, 2008 was 152,833,061.
PART I FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months |
|
|
For the Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(Unaudited) |
|
|
|
|
|
|
|
(Amounts in thousands of U.S. dollars, except |
|
|
|
per share data) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
263,327 |
|
|
$ |
116,421 |
|
|
$ |
512,449 |
|
|
$ |
263,705 |
|
Oil sales |
|
|
30,794 |
|
|
|
14,451 |
|
|
|
52,809 |
|
|
|
23,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
294,121 |
|
|
|
130,872 |
|
|
|
565,258 |
|
|
|
287,448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
8,562 |
|
|
|
5,573 |
|
|
|
19,299 |
|
|
|
10,251 |
|
Production taxes |
|
|
35,776 |
|
|
|
14,694 |
|
|
|
66,711 |
|
|
|
32,207 |
|
Gathering fees |
|
|
8,766 |
|
|
|
6,980 |
|
|
|
18,764 |
|
|
|
13,473 |
|
Transportation charges |
|
|
12,013 |
|
|
|
|
|
|
|
21,671 |
|
|
|
|
|
Depletion and depreciation |
|
|
42,780 |
|
|
|
32,591 |
|
|
|
85,030 |
|
|
|
62,221 |
|
General and administrative |
|
|
4,449 |
|
|
|
3,421 |
|
|
|
8,794 |
|
|
|
6,639 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
112,346 |
|
|
|
63,259 |
|
|
|
220,269 |
|
|
|
124,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
181,775 |
|
|
|
67,613 |
|
|
|
344,989 |
|
|
|
162,657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense), net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(4,543 |
) |
|
|
(4,221 |
) |
|
|
(9,814 |
) |
|
|
(6,921 |
) |
Interest income |
|
|
127 |
|
|
|
309 |
|
|
|
277 |
|
|
|
636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net |
|
|
(4,416 |
) |
|
|
(3,912 |
) |
|
|
(9,537 |
) |
|
|
(6,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax provision |
|
|
177,359 |
|
|
|
63,701 |
|
|
|
335,452 |
|
|
|
156,372 |
|
Income tax provision |
|
|
62,603 |
|
|
|
23,949 |
|
|
|
119,337 |
|
|
|
55,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations |
|
|
114,756 |
|
|
|
39,752 |
|
|
|
216,115 |
|
|
|
100,394 |
|
Income from discontinued operations, net of tax |
|
|
482 |
|
|
|
9,317 |
|
|
|
415 |
|
|
|
15,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
115,238 |
|
|
|
49,069 |
|
|
|
216,530 |
|
|
|
115,660 |
|
Retained earnings, beginning of period |
|
|
989,112 |
|
|
|
691,375 |
|
|
|
887,820 |
|
|
|
624,784 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings, end of period |
|
$ |
1,104,350 |
|
|
$ |
740,444 |
|
|
$ |
1,104,350 |
|
|
$ |
740,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share from continuing operations |
|
$ |
0.75 |
|
|
$ |
0.26 |
|
|
$ |
1.41 |
|
|
$ |
0.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share from discontinued operations |
|
$ |
0.00 |
|
|
$ |
0.06 |
|
|
$ |
0.00 |
|
|
$ |
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per common share |
|
$ |
0.75 |
|
|
$ |
0.32 |
|
|
$ |
1.41 |
|
|
$ |
0.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Earnings per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share from continuing operations |
|
$ |
0.73 |
|
|
$ |
0.25 |
|
|
$ |
1.37 |
|
|
$ |
0.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common share from discontinued operations |
|
$ |
0.00 |
|
|
$ |
0.06 |
|
|
$ |
0.00 |
|
|
$ |
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per common share |
|
$ |
0.73 |
|
|
$ |
0.31 |
|
|
$ |
1.37 |
|
|
$ |
0.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic |
|
|
153,061 |
|
|
|
152,022 |
|
|
|
152,781 |
|
|
|
151,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully diluted |
|
|
157,818 |
|
|
|
158,992 |
|
|
|
157,905 |
|
|
|
159,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
|
|
|
|
(Amounts in thousands of U.S. Dollars) |
|
ASSETS
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
60,344 |
|
|
$ |
10,632 |
|
Restricted cash |
|
|
2,624 |
|
|
|
2,590 |
|
Accounts receivable |
|
|
177,409 |
|
|
|
135,849 |
|
Derivative assets |
|
|
|
|
|
|
5,625 |
|
Inventory |
|
|
6,733 |
|
|
|
13,333 |
|
Prepaid drilling costs and other current assets |
|
|
2,290 |
|
|
|
424 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
249,400 |
|
|
|
168,453 |
|
Oil and gas properties, net, using the full cost method of accounting |
|
|
|
|
|
|
|
|
Proved |
|
|
1,866,026 |
|
|
|
1,537,751 |
|
Unproved |
|
|
36,622 |
|
|
|
36,778 |
|
Property, plant and equipment |
|
|
4,846 |
|
|
|
4,739 |
|
Deferred financing costs, derivative assets and other |
|
|
3,063 |
|
|
|
3,861 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,159,957 |
|
|
$ |
1,751,582 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
213,998 |
|
|
$ |
140,641 |
|
Derivative liabilities |
|
|
54,065 |
|
|
|
|
|
Current taxes payable |
|
|
|
|
|
|
10,839 |
|
Capital cost accrual |
|
|
118,084 |
|
|
|
88,445 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
386,147 |
|
|
|
239,925 |
|
Long-term debt |
|
|
300,000 |
|
|
|
290,000 |
|
Deferred income tax liability |
|
|
376,524 |
|
|
|
341,406 |
|
Other long-term obligations |
|
|
49,686 |
|
|
|
26,672 |
|
Shareholders equity |
|
|
|
|
|
|
|
|
Share capital |
|
|
(16,865 |
) |
|
|
20,050 |
|
Treasury stock |
|
|
(4,142 |
) |
|
|
(59,245 |
) |
Retained earnings |
|
|
1,104,350 |
|
|
|
887,820 |
|
Accumulated other comprehensive (loss) income |
|
|
(35,743 |
) |
|
|
4,954 |
|
|
|
|
|
|
|
|
Total shareholders equity |
|
|
1,047,600 |
|
|
|
853,579 |
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity |
|
$ |
2,159,957 |
|
|
$ |
1,751,582 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
4
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
(Amounts in thousands of U.S. |
|
|
|
Dollars) |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities: |
|
|
|
|
|
|
|
|
Net income for the period |
|
$ |
216,530 |
|
|
$ |
115,660 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Income from discontinued operations, net of tax provision of
$225 and $8,220, respectively |
|
|
(415 |
) |
|
|
(15,266 |
) |
Depletion and depreciation |
|
|
85,030 |
|
|
|
62,221 |
|
Deferred income taxes |
|
|
119,531 |
|
|
|
53,308 |
|
Excess tax benefit from stock based compensation |
|
|
(62,627 |
) |
|
|
(11,548 |
) |
Stock compensation |
|
|
2,755 |
|
|
|
2,736 |
|
Other |
|
|
189 |
|
|
|
43 |
|
Net changes in non-cash working capital: |
|
|
|
|
|
|
|
|
Restricted cash |
|
|
(34 |
) |
|
|
(1,207 |
) |
Accounts receivable |
|
|
(41,560 |
) |
|
|
(14,654 |
) |
Prepaid drilling costs and other current and non-current assets |
|
|
(1,702 |
) |
|
|
(1,006 |
) |
Accounts payable and accrued liabilities |
|
|
71,124 |
|
|
|
42,729 |
|
Other long-term obligations |
|
|
20,424 |
|
|
|
(1,748 |
) |
Current taxes payable |
|
|
(10,839 |
) |
|
|
(2,150 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities from continuing operations |
|
|
398,406 |
|
|
|
229,118 |
|
Net cash provided by operating activities from discontinued operations |
|
|
|
|
|
|
9,522 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
398,406 |
|
|
|
238,640 |
|
|
|
|
|
|
|
|
|
|
Investing activities: |
|
|
|
|
|
|
|
|
Oil and gas property expenditures |
|
|
(409,089 |
) |
|
|
(349,828 |
) |
Investing activities from discontinued operations |
|
|
|
|
|
|
(10,960 |
) |
Post-closing adjustments on sale of subsidiary |
|
|
640 |
|
|
|
|
|
Change in capital cost accrual |
|
|
29,639 |
|
|
|
(9,752 |
) |
Inventory |
|
|
6,600 |
|
|
|
5,837 |
|
Purchase of capital assets |
|
|
(461 |
) |
|
|
(219 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(372,671 |
) |
|
|
(364,922 |
) |
|
|
|
|
|
|
|
|
|
Financing activities: |
|
|
|
|
|
|
|
|
Borrowings on long-term debt |
|
|
332,000 |
|
|
|
135,000 |
|
Payments on long-term debt |
|
|
(322,000 |
) |
|
|
|
|
Deferred financing costs |
|
|
(1,580 |
) |
|
|
(1,082 |
) |
Repurchased shares |
|
|
(68,635 |
) |
|
|
(39,744 |
) |
Excess tax benefit from stock based compensation |
|
|
62,627 |
|
|
|
11,548 |
|
Stock issued for compensation |
|
|
4,934 |
|
|
|
|
|
Proceeds from exercise of options |
|
|
16,631 |
|
|
|
4,867 |
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
23,977 |
|
|
|
110,589 |
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash during the period |
|
|
49,712 |
|
|
|
(15,693 |
) |
Cash and cash equivalents, beginning of period |
|
|
10,632 |
|
|
|
14,574 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
60,344 |
|
|
$ |
(1,119 |
) |
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
5
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All dollar 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
acquisition, exploration, development, and production of oil and 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.
1. SIGNIFICANT ACCOUNTING POLICIES:
The accompanying financial statements, other than the balance sheet data as of December 31,
2007, are unaudited and were prepared from the Companys records. Balance sheet data as of December
31, 2007 was derived from the Companys audited financial statements, but does not include all
disclosures required by U.S. generally accepted accounting principles. 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.
(a) Basis of presentation and principles of consolidation: The consolidated financial
statements include the accounts of the Company and its wholly owned subsidiaries UP Energy
Corporation, Ultra Resources, Inc. and Sino-American Energy through the date of the sale of the
China operations. The Company presents its financial statements in accordance with U.S. Generally
Accepted Accounting Principles (GAAP). All inter-company transactions and balances have been
eliminated upon consolidation.
(b) Cash and cash equivalents: We consider all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
(c) Restricted cash: Restricted cash represents cash received by the Company from production
sold where the final division of ownership of the production is unknown or in dispute. Wyoming law
requires that these funds be held in a federally insured bank in Wyoming.
(d) Capital assets other than oil and gas properties: Capital assets are recorded at cost and
depreciated using the declining-balance method based on a seven-year useful life.
(e) 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). Separate cost centers are maintained for each country in which the Company incurs costs.
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 proved reserves as
determined by independent petroleum engineers. Oil and natural gas
6
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.
Oil and natural gas properties include costs that are excluded from capitalized costs being
amortized. These amounts represent investments in unproved properties and major development
projects. The Company excludes these costs until proved reserves are found or until it is
determined that the costs are impaired. All costs excluded are reviewed, at least quarterly, to
determine if impairment has occurred. The amount of any impairment is transferred to the
capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool).
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 prices in effect on the last
day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a
quarter are the result of a temporary decline and prices improve prior to the issuance of the
financial statements, the increased price may be applied in the computation of the ceiling test.
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 result
in lower DD&A expense 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 effect of
implementing SFAS No. 143 had no effect on the ceiling test calculation as the future cash outflows
associated with settling asset retirement obligations are excluded from this calculation.
(f) Inventories: Materials and supplies inventories are carried at the lower of current
market value or cost. Inventory costs include expenditures and other charges directly and
indirectly incurred in bringing the inventory to its existing condition and location. The Company
uses the weighted average method of recording its inventory. Selling expenses and general and
administrative expenses are reported as period costs and excluded from inventory cost. At June 30,
2008, drilling and completion supplies inventory of $6.7 million primarily includes the cost of
pipe and production equipment that will be utilized during the 2008 drilling program.
(g) Forward natural gas sales transactions: The Company primarily relies on fixed price
physical delivery contracts, which are considered sales in the normal course of business, to manage
its commodity price exposure. The Company, from time to time, also uses derivative instruments as a
way to manage its exposure to commodity prices. (See Note 7).
(h) Income taxes: Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and
their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in income in the period
that includes the enactment date. Valuation allowances are recorded related to deferred tax assets
based on the more likely than not criteria of SFAS No. 109.
Effective January 1, 2007, we adopted FASB Interpretation No. 48 (FIN 48) which requires
that we recognize 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.
(i) Earnings per share: Basic earnings per share is computed by dividing net earnings
attributable to common stock 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.
The following table provides a reconciliation of the components of basic and diluted net
income per common share:
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Net income from continuing operations |
|
$ |
114,756 |
|
|
$ |
39,752 |
|
|
$ |
216,115 |
|
|
$ |
100,394 |
|
Net income from discontinued operations |
|
$ |
482 |
|
|
$ |
9,317 |
|
|
$ |
415 |
|
|
$ |
15,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
115,238 |
|
|
$ |
49,069 |
|
|
$ |
216,530 |
|
|
$ |
115,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
during the period |
|
|
153,061 |
|
|
|
152,022 |
|
|
|
152,781 |
|
|
|
151,975 |
|
Effect of dilutive instruments |
|
|
4,757 |
|
|
|
6,970 |
|
|
|
5,124 |
|
|
|
7,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
during the period including the effects of
dilutive instruments |
|
|
157,818 |
|
|
|
158,992 |
|
|
|
157,905 |
|
|
|
159,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from continuing operations |
|
$ |
0.75 |
|
|
$ |
0.26 |
|
|
$ |
1.41 |
|
|
$ |
0.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from discontinued operations |
|
$ |
0.00 |
|
|
$ |
0.06 |
|
|
$ |
0.00 |
|
|
$ |
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share |
|
$ |
0.75 |
|
|
$ |
0.32 |
|
|
$ |
1.41 |
|
|
$ |
0.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Earnings per Share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from continuing operations |
|
$ |
0.73 |
|
|
$ |
0.25 |
|
|
$ |
1.37 |
|
|
$ |
0.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from discontinued operations |
|
$ |
0.00 |
|
|
$ |
0.06 |
|
|
$ |
0.00 |
|
|
$ |
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share |
|
$ |
0.73 |
|
|
$ |
0.31 |
|
|
$ |
1.37 |
|
|
$ |
0.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(j) Use of estimates: Preparation of consolidated financial statements in accordance with
GAAP requires management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
(k) Accounting for share-based compensation: The Company applies Statement of Financial
Accounting Standards No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R) 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 under SFAS No. 123R for the six months ended June 30,
2008 and 2007 was $2.8 million and $2.7 million, respectively. See Note 4 for additional
information.
(l) Fair Value Accounting. In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This Statement defines
fair value, establishes a framework for measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value measurements. This Statement applies under
other accounting pronouncements that require or permit fair value measurements. Accordingly, this
statement does not require any new fair value measurements. The changes to current practice
resulting from the application of this statement relate to the definition of fair value, the
methods used to measure fair value, and the expanded disclosures about fair value measurements. The
Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured at fair value on a recurring basis,
primarily our commodity derivatives, with no material impact on consolidated results of operations,
financial position or liquidity. For those non-financial assets and liabilities measured or
disclosed at fair value on a non-recurring basis, SFAS No. 157 is effective January 1, 2009.
Implementation of this portion of the standard is not expected to have a material impact on
consolidated results of operations, financial position or liquidity. See Note 9 for additional
information.
(m) Revenue Recognition. Natural gas revenues are recorded based on the entitlement method.
Under the entitlement method, revenue is recorded when title passes based on the Companys net
interest. The Company initially records its entitled share of revenues based on estimated
production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes
that are supported by third party pipeline statements or cash receipts. Since there is a ready
market for natural gas, the Company sells the majority of its products immediately after production
at various locations at which time title and risk of loss pass to the buyer. Gas imbalances occur
when the Company sells more or less than its entitled ownership percentage of total gas production.
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.
(n) Other Comprehensive Income: Other comprehensive income is a term used to define revenues,
expenses, gains and losses that under generally accepted accounting principles impact Shareholders
Equity, excluding transactions with shareholders.
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended |
|
|
For the six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Net income |
|
$ |
115,238 |
|
|
$ |
49,069 |
|
|
$ |
216,530 |
|
|
$ |
115,660 |
|
Unrealized gain (loss) on derivative instruments |
|
|
(5,116 |
) |
|
|
3,028 |
|
|
|
(55,074 |
) |
|
|
3,028 |
|
Taxes benefit (expense) on unrealized gain
(loss) on derivative instruments |
|
|
1,796 |
|
|
|
(1,063 |
) |
|
|
19,331 |
|
|
|
(1,063 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
$ |
111,918 |
|
|
$ |
51,034 |
|
|
$ |
180,787 |
|
|
$ |
117,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2008, the Company recorded a non-current asset of $1.1 million, a current
liability of $54.1 million and a non-current liability of $2.1 million associated with the
derivative instruments included in other comprehensive income.
(o) Reclassifications: Certain amounts in the financial statements of the prior periods have
been reclassified to conform to the current period financial statement presentation. (Refer to
Note 8).
(p) Impact of recently issued accounting pronouncements: In March 2008, the FASB issued SFAS
No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS No. 161). This
statement is intended to improve financial reporting about derivative instruments and hedging
activities by requiring enhanced disclosures to increase transparency about the location and
amounts of derivative instruments in an entitys financial statements; how derivative instruments
and related hedged items are accounted for under SFAS No. 133; and how derivative instruments and
related hedged items affect financial position, financial performance, and cash flows. SFAS No. 161
is effective as of the beginning of an entitys first fiscal year that begins after November 15,
2008. The Company does not anticipate that the implementation of SFAS No. 161 will have a material
impact on the consolidated results of operations, financial position or liquidity.
2. OIL AND GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Developed Properties: |
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental costs |
|
$ |
2,281,171 |
|
|
$ |
1,868,564 |
|
Less accumulated depletion, depreciation and amortization |
|
|
(415,145 |
) |
|
|
(330,813 |
) |
|
|
|
|
|
|
|
|
|
|
1,866,026 |
|
|
|
1,537,751 |
|
|
|
|
|
|
|
|
|
|
Unproven Properties: |
|
|
|
|
|
|
|
|
Acquisition and exploration costs |
|
|
36,622 |
|
|
|
36,778 |
|
|
|
|
|
|
|
|
|
|
$ |
1,902,648 |
|
|
$ |
1,574,529 |
|
|
|
|
|
|
|
|
3. LONG-TERM LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Bank indebtedness |
|
$ |
|
|
|
$ |
290,000 |
|
Senior notes, due 2015 |
|
|
100,000 |
|
|
|
|
|
Senior notes, due 2018 |
|
|
200,000 |
|
|
|
|
|
Other long-term obligations |
|
|
49,686 |
|
|
|
26,672 |
|
|
|
|
|
|
|
|
|
|
$ |
349,686 |
|
|
$ |
316,672 |
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its subsidiary) is a party to a revolving credit
facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012.
This agreement provides an initial loan commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right,
but not the obligation, to increase the amount of its commitment as requested by the Company. In
the event the existing banks increase their commitment to an amount less than the requested
commitment amount, then it would be necessary to add new financial institutions to the credit
facility.
9
Loans under the credit facility are unsecured and bear interest, at our option, based on (A) a
rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on
overnight transactions during the preceding business day plus 50 basis points, or (B) a base
Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of our
consolidated leverage ratio (87.5 basis points per annum as of June 30, 2008).
At June 30, 2008, we had no outstanding borrowings and $500.0 million of available borrowing
capacity under our credit facility.
The facility has restrictive covenants that include the maintenance of a ratio of consolidated
funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to
exceed 31/2 times; and as long as our debt rating is below investment grade, the maintenance of an
annual ratio of the net present value of our oil and gas properties to total funded debt of at
least 1.75 to 1.00. At June 30, 2008, we were in compliance with all of our debt covenants under
our credit facility.
Senior Notes, due 2015 and 2018: On March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes (the Notes) pursuant to a Master Note Purchase
Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the
Companys bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP
Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million
are 5.45% Senior Notes due 2015.
Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the
borrowings available to us under the revolving credit facility.
The Notes are pre-payable in whole or in part at any time. The Notes are subject to
representations, warranties, covenants and events of default customary for a senior note financing.
If payment default occurs, any Note holder may accelerate its Notes; if a non-payment default
occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the
Notes. At June 30, 2008, we were in compliance with all of our debt covenants under the Notes.
Other long-term obligations: These costs primarily relate to the long-term portion of
production taxes payable, a liability associated with imbalanced production, the long-term portion
of costs associated with our compensation programs and our asset retirement obligations.
4. SHARE BASED COMPENSATION:
Valuation and Expense Information under SFAS 123R
The following table summarizes share-based compensation expense under SFAS No. 123R for the
six months ended June 30, 2008 and 2007, respectively, which was allocated as follows:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
2008 |
|
2007 |
Total cost of share-based payment plans |
|
$ |
4,866 |
|
|
$ |
4,649 |
|
Amounts capitalized in fixed assets |
|
$ |
2,111 |
|
|
$ |
1,913 |
|
Amounts charged against income, before income tax benefit |
|
$ |
2,755 |
|
|
$ |
2,736 |
|
Amount of related income tax benefit recognized in income |
|
$ |
967 |
|
|
$ |
977 |
|
The fair value of each share option award is estimated on the date of grant using a
Black-Scholes pricing model based on assumptions noted in the following table. The Companys
employee stock options have various restrictions including vesting provisions and restrictions on
transfers and hedging, among others, and are often exercised prior to their contractual maturity.
Expected volatilities used in the fair value estimate are based on historical volatility of the
Companys stock. The Company uses historical data to estimate share option exercises, expected term
and employee departure behavior used in the Black-Scholes pricing model. Groups of employees
(executives and non-executives) that have similar historical behavior are considered separately for
purposes of determining the expected term used to estimate fair value. The assumptions utilized
result from differing pre- and post-
10
vesting behaviors among executive and non-executive groups. The risk-free rate for periods
within the contractual term of the share option is based on the U.S. Treasury yield curve in effect
at the time of grant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
June 30, 2008 |
|
June 30, 2007 |
|
|
Non-Executives |
|
Executives |
|
Non-Executives |
|
Executives |
Expected volatility |
|
|
41.22 - 42.47 |
% |
|
|
42.5 |
% |
|
|
42.54 - 43.70 |
% |
|
|
44.40 |
% |
Expected dividends |
|
|
0 |
% |
|
|
0 |
% |
|
|
0 |
% |
|
|
0 |
% |
Expected term (in years) |
|
|
5.01 - 5.08 |
|
|
|
5.98 |
|
|
|
4.75 - 5.02 |
|
|
|
5.53 |
|
Risk free rate |
|
|
2.48 - 3.41 |
% |
|
|
2.98 |
% |
|
|
4.52 - 5.07 |
% |
|
|
4.69 |
% |
Expected forfeiture rate |
|
|
15.0 |
% |
|
|
15.0 |
% |
|
|
14.0 |
% |
|
|
14.0 |
% |
Changes in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for the six months ended June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
Number of |
|
|
Exercise Price |
|
|
|
Options |
|
|
(US$) |
|
Balance, December 31, 2007 |
|
|
7,589 |
|
|
$0.25 to $67.73 |
|
|
|
|
|
|
|
|
Granted |
|
|
183 |
|
|
$71.72 to $87.59 |
|
Exercised |
|
|
(2,325 |
) |
|
$0.25 to $67.73 |
|
|
|
|
|
|
|
|
Balance, June 30, 2008 |
|
|
5,447 |
|
|
$0.25 to $87.59 |
|
|
|
|
|
|
|
|
PERFORMANCE SHARE PLANS:
Long-Term Equity-Based Incentives. In 2005, we adopted the Long Term Incentive Plan (LTIP)
in order to further align the interests of key employees with shareholders and give key employees
the opportunity to share in the long-term performance of the Company by achieving specific
corporate financial and operational goals. Participants are recommended by the CEO and approved by
the Compensation Committee. Selected officers, managers and other key employees are eligible to
participate in the LTIP which has two components, an LTIP Stock Option Award and an LTIP Common
Stock Award.
Under the LTIP, each year the Compensation Committee establishes a percentage of base salary
for each participant which is multiplied by the participants base salary to derive an LTI Value
(Long Term Incentive Value). With respect to LTIP Stock Option Awards, options are awarded equal
to one half of the LTI Value based on the fair value on the date of grant (using Black-Scholes
methodology).
The other half of the LTI Value is the target amount that may be awarded to the participant
as an LTIP Common Stock Award at the end of a three year performance period. The Compensation
Committee establishes performance measures at the beginning of each three year overlapping
performance period. Each participant is also assigned threshold and maximum award levels in the
event that performance is below or above target levels. Awards are expressed as dollar targets and
become payable in common shares at the end of each performance period based on the Companys
overall performance during such period. A new three year period begins each January. Participants
must be employed by the Company when an award is distributed in order to receive an award.
For the performance periods January 2006 December 2008 (2006 LTIP), January 2007
December 2009 (2007 LTIP), and January 2008 2010 (2008 LTIP), the Compensation Committee
established the following performance measures: return on equity, reserve replacement ratio, and
production growth.
For the six months ended June 30, 2008, the Company recognized $0.3 million, $0.4 million and
$0.3 million in pre-tax compensation expense related to the 2006 LTIP, 2007 LTIP and 2008 LTIP,
respectively. For the six months ended June 30, 2007, the Company recognized $0.3 million and $0.3
million in pre-tax compensation expense related to the 2006 LTIP and 2007 LTIP, respectively. The
amounts recognized during the first six months of 2008 and 2007 assume that maximum performance
objectives are attained. If the Company ultimately attains maximum performance objectives, the
associated total compensation cost, estimated at
11
June 30, 2008, for the three year performance periods would be approximately $2.6 million,
$3.3 million and $3.1 million (before taxes) related to the 2006 LTIP, 2007 LTIP and 2008 LTIP,
respectively.
In 2008, the Company established the second performance period for the Best in Class program
for all employees. The first performance period ended December 31, 2007 with the resulting payout
in the second quarter of 2008. The Best in Class program recognizes and financially rewards the
collective efforts of all of our employees in achieving sustained industry leading performance and
the enhancement of shareholder value. Under the Best in Class program, on January 1, 2008 or the
employment date if subsequent to January 1, 2008, all employees received a contingent award of
stock units equal to $60,000 worth of our common stock based on the average high and low share
price on the date of grant. Employees joining the Company after January 1, 2008 will participate on
a pro rata basis based on their length of employment during the performance period. The number of
units that will vest and become payable is based on our performance relative to the industry during
a three-year performance period beginning January 1, 2008, and ending December 31, 2010, and are
set at threshold (50%), target (100%) and maximum (150%) levels. For each vested unit, the
participant will receive one share of common stock. The performance measures are all sources
finding and development cost and full cycle economics.
For the six months ended June 30, 2008, the Company recognized $0.3 million in pre-tax
compensation expense related to the Best in Class program. For the six months ended June 30, 2007,
the Company recognized $0.3 million in pre-tax compensation expense related to the first
performance period of the Best in Class program. The amount recognized for the six months ended
June 30, 2008 assumes that target performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total compensation cost will be approximately
$3.0 million before income taxes.
5. SHARE REPURCHASE PROGRAM:
On May 17, 2006, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate $1 billion of the Companys outstanding common stock
which has been and will be funded by cash on hand and the Companys senior credit facility.
Pursuant to this authorization, the Company has commenced a program to purchase up to $500.0
million of the Companys outstanding shares through open market transactions or privately
negotiated transactions. The stock repurchase will be funded with cash held in an Ultra Resources
bank account or the Companys senior credit facility.
The following tables summarize the Companys share repurchases in total (open market
repurchases plus net share settlements) as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted Average |
|
|
|
|
TOTAL |
|
Purchased |
|
|
Price per Share |
|
|
$ Value |
|
1st Quarter 2008 |
|
|
397 |
|
|
$ |
75.25 |
|
|
$ |
29,829 |
|
2nd Quarter 2008 |
|
|
452 |
|
|
$ |
85.97 |
|
|
$ |
38,807 |
|
Prior |
|
|
5,694 |
|
|
$ |
51.73 |
|
|
$ |
294,549 |
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008 |
|
|
6,543 |
|
|
$ |
55.52 |
|
|
$ |
363,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted Average |
|
|
|
|
OPEN MARKET |
|
Purchased |
|
|
Price per Share |
|
|
$ Value |
|
1st Quarter 2008 |
|
|
214 |
|
|
$ |
75.53 |
|
|
$ |
16,139 |
|
2nd Quarter 2008 |
|
|
210 |
|
|
$ |
84.13 |
|
|
$ |
17,643 |
|
Prior |
|
|
5,401 |
|
|
$ |
51.19 |
|
|
$ |
276,442 |
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008 |
|
|
5,825 |
|
|
$ |
53.27 |
|
|
$ |
310,224 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Weighted Average |
|
|
|
|
NET SHARE SETTLEMENTS |
|
Purchased |
|
|
Price per Share |
|
|
$ Value |
|
1st Quarter 2008 |
|
|
183 |
|
|
$ |
74.92 |
|
|
$ |
13,690 |
|
2nd Quarter 2008 |
|
|
242 |
|
|
$ |
87.57 |
|
|
$ |
21,164 |
|
Prior |
|
|
293 |
|
|
$ |
61.73 |
|
|
$ |
18,107 |
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008 |
|
|
718 |
|
|
$ |
73.79 |
|
|
$ |
52,961 |
|
12
Subsequent to June 30, 2008 and through July 31, 2008, the Company has repurchased $67.8
million of its outstanding common stock in open market repurchases or net share settlements.
6. INCOME TAXES:
The amount of unrecognized tax benefits did not materially change as of June 30, 2008. It is
expected that the amount of unrecognized tax benefits may change in the next twelve months;
however, Ultra does not expect the change to have a significant impact on the results of operations
or the financial position of the Company. Interest expense or penalties recognized during the six
months ended June 30, 2008 were immaterial.
Ultras effective tax rate is 35.6% for the six months ended June 30, 2008 and 35.8% for the
same period in 2007.
7. DERIVATIVE FINANCIAL INSTRUMENTS:
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 Wyoming natural gas production. Historically, prices received for natural gas production
have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural
gas prices are derived from the financial statements which include the effects of hedging and
natural gas balancing.
The Company primarily relies on fixed price forward gas sales to manage its commodity price
exposure. These fixed price forward gas sales are considered normal sales. The Company, from time
to time, also uses derivative instruments to manage its exposure to commodity prices. The Company
has periodically entered into fixed price to index price swap agreements in order to hedge a
portion of its natural gas production. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas index prices as published by such
publications as Inside FERC Gas Market Report. Under SFAS No. 133, all derivative
instruments are recorded on the balance sheet at fair value. Changes in the derivatives fair value
are recognized currently in earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) to the extent the hedge is effective. At June 30, 2008, all hedges were
considered effective as the hedging instruments offset the change in the hedged transactions cash
flows for the risk being hedged. For qualifying fair value hedges, the gain or loss on the
derivative is offset by related results of the hedged item in the income statement. Gains and
losses on hedging instruments included in accumulated other comprehensive (loss) income are
reclassified to oil and natural gas sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as
derivative assets and liabilities at market value in the consolidated balance sheet, and the
associated unrealized gains and losses are recorded as current expense or income in the
consolidated statement of operations. The Company currently does not have any derivative contracts
in place that do not qualify as cash flow hedges.
The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming
delivery points to hedge its commodity price exposure. The Company had the following fixed price
physical delivery contracts in place on behalf of its interest and those of other parties at June
30, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program
which had the effect of increasing the Companys average net interest in physical gas sales from
80% to approximately 91%.)
|
|
|
|
|
|
|
|
|
|
|
Volume- |
|
Average |
Remaining Contract Period |
|
MMBTU/Day |
|
Price/MMBTU |
Calendar 2008
|
|
|
100,000 |
|
|
$ |
6.83 |
|
Summer 2008 (July October)
|
|
|
20,000 |
|
|
$ |
6.88 |
|
Calendar 2009
|
|
|
10,000 |
|
|
$ |
7.51 |
|
Summer 2009 (April October)
|
|
|
90,000 |
|
|
$ |
7.06 |
|
At June 30, 2008, the Company had the following open commodity derivative contracts to manage
price risk on a portion of its natural gas production whereby the Company receives the fixed price
and pays the variable price (all prices NWPL Rockies basis).
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume- |
|
Average |
|
Unrealized |
|
|
|
|
MMBTU/ |
|
Price/ |
|
Loss (000s) at |
Type |
|
Remaining Contract Period |
|
Day |
|
MMBTU |
|
6/30/2008* |
Swap
|
|
July 2008 Oct 2008
|
|
|
190,000 |
|
|
$ |
7.19 |
|
|
$ |
(40,801 |
) |
Swap
|
|
Jan 2009 Dec 2009
|
|
|
30,000 |
|
|
$ |
7.35 |
|
|
$ |
(14,273 |
) |
|
|
|
* |
|
Unrealized losses are not adjusted for income tax effect. |
For the six months ended June 30, 2008, the Company recognized costs associated with
financially settled swaps to counterparties totaling $24.2 million as its net realization from
hedging activities, which was recognized as a reduction of natural gas sales on the income
statement.
8. DISCONTINUED OPERATIONS:
During the third quarter of 2007, we made the decision to dispose of Sino-American Energy
Corporation, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in
the Pinedale Field in southwest Wyoming. The reserve volumes sold represent all of Ultras
international assets and, previously, were the only results included in our foreign operating
segment.
On September 26, 2007, our wholly-owned subsidiary, UP Energy Corporation, a Nevada
corporation, entered into a definitive share purchase agreement with an effective date of June 30,
2007 and a closing date of October 22, 2007 in order to sell all of the outstanding shares of
Sino-American Energy Corporation (Sino-American), a Texas corporation, for a total purchase price
of US$223.0 million, subject to adjustments. The Company recorded results of operations for the
China properties through the close date of October 22, 2007.
The Company has accounted for its Sino-American operations as discontinued operations and has
reclassified prior period financial statements to exclude these businesses from continuing
operations. A summary of financial information related to the Companys discontinued operations is
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months |
|
|
For the Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Operating revenues |
|
$ |
|
|
|
$ |
25,951 |
|
|
$ |
|
|
|
$ |
45,568 |
|
Post closing adjustment on sale of subsidiary |
|
|
743 |
|
|
|
|
|
|
|
640 |
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
12,399 |
|
|
|
|
|
|
|
22,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax provision |
|
|
743 |
|
|
|
13,552 |
|
|
|
640 |
|
|
|
23,486 |
|
Income tax provision |
|
|
261 |
|
|
|
4,235 |
|
|
|
225 |
|
|
|
8,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of tax |
|
$ |
482 |
|
|
$ |
9,317 |
|
|
$ |
415 |
|
|
$ |
15,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9. FAIR VALUE MEASUREMENTS:
On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurement. We adopted SFAS
No. 157 effective January 1, 2008. SFAS No. 157 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. The statement requires fair value measurements be classified and disclosed in one of the
following categories:
14
|
|
|
Level 1:
|
|
Quoted prices (unadjusted) in active markets for identical assets
and liabilities that we have the ability to access at the
measurement date. |
|
|
|
Level 2:
|
|
Inputs other than quoted prices included within Level 1 that are
either directly or indirectly observable for the asset or
liability, 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 cash flow hedges
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).
The following table presents for each hierarchy level our assets and liabilities, including
both current and noncurrent portions, measured at fair value on a recurring basis, as of June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
|
|
|
$ |
1,071 |
|
|
$ |
|
|
|
$ |
1,071 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
|
|
|
$ |
56,145 |
|
|
$ |
|
|
|
$ |
56,145 |
|
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. The derivative
transactions are placed with major financial institutions or with counterparties of high credit
quality that present minimal credit risks to the Company. 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.
10. 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.
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 consolidated financial statements and related notes of the
Company. Except as otherwise indicated all amounts are expressed in U.S. Dollars. We operate in one
industry segment, natural gas and oil exploration and development with one geographical segment;
the United States. (See Note 8 for a discussion regarding the sale of our Chinese assets).
The Company currently generates substantially all of its revenue, earnings and cash from the
production and sales of natural gas and oil from its property in southwest Wyoming. The price of
natural gas in the southwest Wyoming region is a critical factor to the Companys business. The
price of gas in southwest Wyoming historically has been volatile. The average realizations for the
period 2003-2008 have ranged from $2.33 to $8.64 per Mcf. This volatility could be detrimental to
the Companys financial performance. The Company seeks to limit the impact of this volatility on
its results by entering into fixed price forward physical delivery contracts
15
and swap agreements for gas in southwest Wyoming. During the quarter ended June 30, 2008, the
average price realization for the Companys natural gas was $8.06 per Mcf, including the effects of
hedging. The Companys average price realization for natural gas was $8.80 per Mcf, excluding the
effects of hedging.
The Company has grown its natural gas and oil production significantly over the past three
years and management believes it has the ability to continue growing production by drilling already
identified locations on its leases in Wyoming. The Company delivered 23% production growth from
continuing operations on an Mcfe basis during the quarter ended June 30, 2008 as compared to the
same quarter in 2007.
Rockies Express Pipeline. In December 2005, the Company agreed to become an anchor shipper on
the Rockies Express Pipeline (REX) securing pipeline infrastructure providing sufficient capacity
to transport a portion of its natural gas production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas in the future. The Companys commitment involves
capacity of 200,000 MMBtu per day of natural gas for a term of 10 years (beginning in the first
quarter of 2008), and the Company is obligated to pay REX certain demand charges related to its
rights to hold this firm transportation capacity as an anchor shipper. The pipeline will be
completed in two (2) phases: REX West (Wyoming to Missouri) and REX East (Missouri to Ohio).
During the quarter ended June 30, 2008, the REX West pipeline was extended from the ANR
delivery point in Brown County, Kansas to the Panhandle Eastern Pipeline system at Audrain County,
Missouri and placed into service. With the completion of this segment, the Company is able to
deliver its firm capacity of 200,000 MMBtu per day of natural gas from Wyoming to markets in the
mid-west.
On May 30, 2008, the FERC issued a Certificate of Public Convenience and Necessity for the REX
East project. Kinder Morgan, the managing member of REX, has indicated that the current schedule
anticipates REX East to be operational by the end of 2008 to pipeline interconnections near
Lebannon, Ohio. Kinder Morgan has further advised that, when fully completed, (estimated to be
Mid-Year 2009) the REX East pipeline will provide up to 1.8 Bcf per day of natural gas
transportation capacity from the Rockies to Clarington, Ohio.
Discontinued Operations. On September 27, 2007, the Company announced the execution of a
stock purchase agreement for the sale of Sino-American Energy Corporation which represents all of
Ultras interest in Bohai Bay, China for $223 million. Despite having owned Sino-American in the
first half of 2007, under generally accepted accounting principles (GAAP), its operations have
been reclassified as Discontinued Operations for the entire quarter. As a result, production,
revenues and expenses associated with Sino-American have been removed from continuing operations
and reclassified to discontinued operations. The sale closed on October 22, 2007, with an effective
date of June 30, 2007.
Fair Value Measurements. The Company adopted SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are
measured at fair value on a recurring basis, primarily our commodity derivatives, with no material
impact on consolidated results of operations, financial position or liquidity. See Note 9 for
additional information.
SFAS No. 157 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 measurement date
and establishes a three level hierarchy for measuring fair value. The valuation assumptions
utilized to measure the fair value of the Companys cash flow hedges 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. The derivative transactions are placed with
major financial institutions or with counter-parties of high credit quality, which in the Companys
opinion, present minimal credit risks to the Company. 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.
16
The fair values summarized below were determined in accordance with the requirements of SFAS
No. 157. In addition, we aligned the categories below with the Level 1, 2, and 3 fair value
measurements as defined by SFAS No. 157. The balance of net unrealized gains and losses recognized
for our energy-related derivative instruments at June 30, 2008 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 |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
|
|
|
$ |
1,071 |
|
|
$ |
|
|
|
$ |
1,071 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives |
|
$ |
|
|
|
$ |
56,145 |
|
|
$ |
|
|
|
$ |
56,145 |
|
|
|
|
(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. |
Share-Based Payment Arrangements. The Company applies Statement of Financial Accounting
Standards No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R) 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 under SFAS No. 123R for the six months ended June 30,
2008 and 2007 was $2.8 million and $2.7 million, respectively. At June 30, 2008, there was $11.2
million of total unrecognized compensation cost related to non-vested share-based compensation
arrangements granted under stock option plans. That cost is expected to be recognized over a
weighted average period of 1.9 years. See Note 4 for additional information.
SFAS No. 123R requires companies to estimate the fair value of share-based payment awards on
the date of grant using an option-pricing model. The Company utilized a Black-Scholes option
pricing model to measure the fair value of stock options granted to employees. The value of the
portion of the award that is ultimately expected to vest is recognized as expense over the
requisite service periods in the Companys Consolidated Statement of Operations. The Companys
determination of fair value of share-based payment awards on the date of grant using an
option-pricing model is affected by the Companys stock price as well as assumptions regarding a
number of highly complex and subjective variables. These variables include, but are not limited to
the Companys expected stock price volatility over the term of the awards and actual and projected
employee stock option exercise behaviors.
Full Cost Method of Accounting. The Company uses the full cost method of accounting for oil
and gas operations whereby 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. Inflation has not had a material impact on the
Companys results of operations and is not expected to have a material impact on the Companys
results of operations in the future.
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 prices in effect on the last
day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a
quarter are the result of a temporary decline and prices improve prior to the issuance of the
financial statements, the increased price may be applied in the computation of the ceiling test.
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 result
in lower DD&A expense in future periods.
17
A write-down may not be reversed in future periods, even
though higher oil and natural gas prices may subsequently increase the ceiling.
RESULTS OF OPERATIONS
QUARTER ENDED JUNE 30, 2008 VS. QUARTER ENDED JUNE 30, 2007
During the second quarter of 2008, production from continuing operations increased 23% on a
gas equivalent basis to 34.3 Bcfe from 27.9 Bcfe for the same quarter in 2007 attributable to the
Companys successful drilling activities during 2007 and in the first six months of 2008. Realized
natural gas prices, including the effect of hedging, increased 84% to $8.06 per Mcf in the second
quarter of 2008 as compared to $4.38 for the second quarter of 2007. The increase in realized
average natural gas prices together with the increase in production contributed to a 125% increase
in revenues from continuing operations to $294.1 million as compared to $130.9 million in 2007.
Lease operating expense (LOE) increased to $8.6 million at June 30, 2008 compared to $5.6
million at June 30, 2007 due primarily to increased production volumes. On a unit of production
basis, LOE costs increased to $0.25 per Mcfe at June 30, 2008 compared to $0.20 per Mcfe at June
30, 2007 mainly due to costs related to non-operated properties for water disposal expenses.
During the second quarter of 2008, production taxes were $35.8 million compared to $14.7
million during the second quarter of 2007, or $1.04 per Mcfe (12.2% of revenues), compared to $0.53
per Mcfe (11.2% of revenues). The increase in per unit taxes is attributable to increased sales
revenues as a result of increased production and higher realized gas prices received during the
quarter ended June 30, 2008 as compared to the same period in 2007. Production taxes are calculated
based on a percentage of revenue from production. Therefore, higher prices received increased
production taxes on a per unit basis.
Gathering fees increased to $8.8 million at June 30, 2008 compared to $7.0 million at June 30,
2007 largely due to increased production volumes. On a per unit basis, gathering fees remained
relatively flat at $0.26 per Mcfe for the three months ended June 30, 2008 as compared to $0.25 per
Mcfe for the same period in 2007.
To secure pipeline infrastructure providing sufficient capacity to transport a portion of the
Companys natural gas production away from southwest Wyoming and to provide for reasonable basis
differentials for its natural gas, the Company incurred transportation demand charges totaling
$12.0 million for the quarter ended June 30, 2008 in association with REX Pipeline demand charges.
Depletion, depreciation and amortization (DD&A) expenses increased to $42.8 million during
the quarter ended June 30, 2008 from $32.6 million for the same period in 2007, attributable to
increased production volumes and a higher depletion rate, due mainly to increased development
costs. On a unit basis, DD&A increased to $1.25 per Mcfe at June 30, 2008 from $1.17 at June 30,
2007.
General and administrative expenses increased to $4.4 million ($0.13 per Mcfe) at June 30,
2008 compared to $3.4 million ($0.12 per Mcfe) for the same period in 2007. The increase in
general and administrative expenses during 2008 is primarily attributable to increased Medicare
taxes as a result of increased employee stock option exercises during the quarter months ended June
30, 2008.
Interest expense remained relatively flat at $4.5 million during the quarter ended June 30,
2008 compared to $4.2 million during the same period in 2007. At June 30, 2008 and 2007, the
Company had $300.0 million in borrowings outstanding.
Net income before income taxes increased to $177.4 million for the quarter ended June 30, 2008
from $63.7 million for the same period in 2007 primarily as a result of increased natural gas
prices and increased production during the quarter ended June 30, 2008.
The income tax provision increased to $62.6 million for the three months ended June 30, 2008
as compared to $23.9 million for the three months ended June 30, 2007 due to higher pre-tax income.
Income from discontinued operations, net of tax, (which is comprised entirely of results
associated with the Chinese assets) decreased to $0.5 million for the quarter ended June 30, 2008
from $9.3 million for the same period in 2007. The sale closed on October 22, 2007. See Note 8 for
additional information.
18
For the quarter ended June 30, 2008, net income increased to $115.2 million or $0.73 per
diluted share as compared with $49.1 million or $0.31 per diluted share for the same period in 2007
primarily attributable to increased gas prices realized in 2008 as well as increased natural gas
production.
SIX MONTHS ENDED JUNE 30, 2008 VS. SIX MONTHS ENDED JUNE 30, 2007
During the six months ended June 30, 2008, production from continuing operations increased 27%
on a gas equivalent basis to 68.4 Bcfe from 53.9 Bcfe for the same period in 2007 attributable to
the Companys successful drilling activities during 2007 and in the first six months of 2008.
Realized natural gas prices, including the effect of hedging, increased 53% to $7.86 per Mcf for
the six months ended June 30, 2008 as compared to $5.13 for the same period in 2007. The increase
in realized average natural gas prices together with the increase in production contributed to a
97% increase in revenues from continuing operations to $565.3 million as compared to $287.4 million
in 2007.
LOE increased to $19.3 million at June 30, 2008 compared to $10.3 million at June 30, 2007 due
primarily to increased production volumes. On a unit of production basis, LOE costs increased to
$0.28 per Mcfe at June 30, 2008 compared to $0.19 per Mcfe at June 30, 2007 mainly due to costs
related to non-operated properties for water disposal expenses.
During the first half of 2008, production taxes were $66.7 million compared to $32.2 million
during the same period of 2007, or $0.98 per Mcfe (11.8% of revenues), compared to $0.60 per Mcfe
(11.2% of revenues). The increase in per unit taxes is attributable to increased sales revenues as
a result of increased production and higher realized gas prices received during the six months
ended June 30, 2008 as compared to the same period in 2007. Production taxes are calculated based
on a percentage of revenue from production. Therefore, higher prices received increased production
taxes on a per unit basis.
Gathering fees increased to $18.8 million at June 30, 2008 compared to $13.5 million at June
30, 2007 largely due to increased production volumes. On a per unit basis, gathering fees increased
to $0.27 per Mcfe for the six months ended June 30, 2008 as compared to $0.25 per Mcfe for the same
period in 2007.
To secure pipeline infrastructure providing sufficient capacity to transport a portion of the
Companys natural gas production away from southwest Wyoming and to provide for reasonable basis
differentials for its natural gas, the Company incurred transportation demand charges totaling
$21.7 million for the six months ended June 30, 2008 in association with the REX Pipeline demand
charges.
DD&A expenses increased to $85.0 million during the six months ended June 30, 2008 from $62.2
million for the same period in 2007, attributable to increased production volumes and a higher
depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.24
per Mcfe at June 30, 2008 from $1.15 at June 30, 2007.
General and administrative expenses increased to $8.8 million ($0.13 per Mcfe) at June 30,
2008 compared to $6.6 million ($0.12 per Mcfe) for the same period in 2007. The increase in
general and administrative expenses during 2008 is primarily attributable to increased Medicare
taxes as a result of increased employee stock option exercises during the six months ended June 30,
2008.
Interest expense increased to $9.8 million during the six months ended June 30, 2008 from $6.9
million during the same period in 2007. The increase is related to higher average outstanding debt
balances during the period ended June 30, 2008 as compared to the same period in 2007. At June 30,
2008 and 2007, the Company had $300.0 million in borrowings outstanding.
Net income before income taxes increased to $335.5 million for the six months ended June 30,
2008 from $156.4 million for the same period in 2007 primarily as a result of increased natural gas
prices and increased production during the six months ended June 30, 2008.
The income tax provision increased to $119.3 million for the six months ended June 30, 2008 as
compared to $56.0 million for the six months ended June 30, 2007 due to higher pre-tax income.
Income from discontinued operations, net of tax, (which is comprised entirely of results
associated with the Chinese assets) decreased to $0.4 million for the six months ended June 30,
2008 from $15.3 million for the same period in 2007. The sale closed on October 22, 2007. See Note
8 for additional information.
19
For the six months ended June 30, 2008, net income increased to $216.5 million or $1.37 per
diluted share as compared with $115.7 million or $0.73 per diluted share for the same period in
2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural
gas production.
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.
GAAP. In addition, application of generally accepted accounting principles requires the use of
estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as
of the date of the financial statements as well as the revenues and expenses reported during the
period. Changes in these estimates, judgments and assumptions will occur as a result of future
events, and, accordingly, actual results could differ from amounts estimated.
LIQUIDITY AND CAPITAL RESOURCES
During the six month period ended June 30, 2008, the Company relied on cash provided by
operations along with borrowings under the senior credit facility and the issuance of the Notes to
finance its capital expenditures. The Company participated in the drilling of 190 wells in Wyoming.
For the six month period ended June 30, 2008, net capital expenditures were $409.1 million. At June
30, 2008, the Company reported a cash position of $60.3 million compared to a cash deficit of $1.1
million at June 30, 2007. Working capital at June 30, 2008 was a deficit of $136.7 million compared
to working capital of $34.1 million at June 30, 2007. As of June 30, 2008, the Company had no bank
indebtedness outstanding and $500.0 million of available borrowing capacity under its facility.
Other long-term obligations of $49.7 million at June 30, 2008 is comprised of items payable in more
than one year, primarily related to production taxes.
The Companys positive cash provided by operating activities, along with availability under
the senior credit facility, are projected to be sufficient to fund the Companys budgeted capital
expenditures for 2008, which are currently projected to be $945.0 million. Of the $945.0 million
budget, the Company plans to allocate approximately 97% to Wyoming and 3% to Pennsylvania.
Bank indebtedness. The Company (through its subsidiary) is a party to a revolving credit
facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012.
This agreement provides an initial loan commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right,
but not the obligation, to increase the amount of its commitment as requested by the Company. In
the event the existing banks increase their commitment to an amount less than the requested
commitment amount, then it would be necessary to add new financial institutions to the credit
facility.
Loans under the credit facility are unsecured and bear interest, at our option, based on (A) a
rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on
overnight transactions during the preceding business day plus 50 basis points, or (B) a base
Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of our
consolidated leverage ratio (87.5 basis points per annum as of June 30, 2008).
The facility has restrictive covenants that include the maintenance of a ratio of consolidated
funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to
exceed 31/2 times; and as long as our debt rating is below investment grade, the maintenance of an
annual ratio of the net present value of our oil and gas properties to total funded debt of at
least 1.75 to 1.00. At June 30, 2008, we were in compliance with all of our debt covenants under
our credit facility.
Senior Notes, due 2015 and 2018: On March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes pursuant to a Master Note Purchase Agreement
between the Company and the purchasers of the Notes. The Notes rank pari passu with the Companys
bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy
Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are
5.45% Senior Notes due 2015.
Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the
borrowing available to us under our revolving credit facility.
The Notes are pre-payable in whole or in part at any time. The Notes are subject to
representations, warranties, covenants and events of default customary for a senior note financing.
If payment default occurs, any Note holder may accelerate its Notes; if a non-
20
payment default
occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the
Notes. At June 30, 2008, we were in compliance with all of our debt covenants under the Notes.
Operating Activities. During the six months ended June 30, 2008, net cash provided by
operating activities was $398.4 million, a 67% increase over the $238.6 million for the same period
in 2007. The increase in net cash provided by operating activities was largely attributable to the
increase in production and realized natural gas prices during the six months ended June 30, 2008 as
compared to the same period in 2007.
Investing Activities. During the six months ended June 30, 2008, net cash used in investing
activities was $372.7 million as compared to $364.9 million for the same period in 2007. The
increase in net cash used in investing activities is largely due to increased capital expenditures
associated with the Companys drilling activities in 2008.
Financing Activities. During the six months ended June 30, 2008, net cash provided by
financing activities was $24.0 million as compared to $110.6 million for the same period in 2007.
The decrease in cash provided by net financing activities is primarily attributable to decreased
net borrowings during the six months ended June 30, 2008 as compared to the same period in 2007.
OFF BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of June 30, 2008.
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 our 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, 2007 for additional risks related to the Companys business.
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Companys major market risk exposure is in the pricing applicable to its natural gas
production. Realized pricing is currently driven primarily by the prevailing price for the
Companys Wyoming natural gas production. Historically, prices received for natural gas production
have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural
gas prices are derived from the financial statements which include the effects of hedging and
natural gas balancing.
The Company primarily relies on fixed price forward gas sales to manage its commodity price
exposure. These fixed price forward gas sales are considered normal sales. The Company, from time
to time, also uses derivative instruments to manage its exposure to commodity prices. The Company
has periodically entered into fixed price to index price swap agreements in order to hedge a
portion of its natural gas production. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas index prices as published by such
publications as Inside FERC Gas Market Report. Under SFAS No. 133, all derivative
21
instruments are recorded on the balance sheet at fair value. Changes in the derivatives fair value
are recognized currently in earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) to the extent the hedge is effective. At June 30, 2008, all hedges were
considered
effective as the hedging instruments offset the change in the hedged transactions cash flows
for the risk being hedged. For qualifying fair value hedges, the gain or loss on the derivative is
offset by related results of the hedged item in the income statement. Gains and losses on hedging
instruments included in accumulated other comprehensive (loss) income are reclassified to oil and
natural gas sales revenue in the period that the related production is delivered. Derivative
contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and
liabilities at market value in the consolidated balance sheet, and the associated unrealized gains
and losses are recorded as current expense or income in the consolidated statement of operations.
The Company currently does not have any derivative contracts in place that do not qualify as cash
flow hedges.
On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurement. SFAS No. 157
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 measurement date and establishes
a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the
fair value of the Companys cash flow hedges 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. The derivative transactions are placed with major
financial institutions or with counterparties of high credit quality that present minimal credit
risks to the Company. 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 Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming
delivery points to hedge its commodity price exposure. The Company had the following fixed price
physical delivery contracts in place on behalf of its interest and those of other parties at June
30, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program
which had the effect of increasing the Companys average net interest in physical gas sales from
80% to approximately 91%.)
|
|
|
|
|
|
|
|
|
|
|
Volume- |
|
Average |
Remaining Contract Period |
|
MMBTU/Day |
|
Price/MMBTU |
Calendar 2008 |
|
|
100,000 |
|
|
$ |
6.83 |
|
Summer 2008 (July October) |
|
|
20,000 |
|
|
$ |
6.88 |
|
Calendar 2009 |
|
|
10,000 |
|
|
$ |
7.51 |
|
Summer 2009 (April October) |
|
|
90,000 |
|
|
$ |
7.06 |
|
At June 30, 2008, the Company had the following open commodity derivative contracts to manage
price risk on a portion of its natural gas production whereby the Company receives the fixed price
and pays the variable price (all prices NWPL Rockies basis).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume- |
|
Average |
|
Unrealized |
|
|
|
|
|
|
MMBTU/ |
|
Price/ |
|
Loss (000s) at |
Type |
|
Remaining Contract Period |
|
Day |
|
MMBTU |
|
6/30/2008* |
Swap |
|
July 2008 Oct 2008 |
|
|
190,000 |
|
|
$ |
7.19 |
|
|
$ |
(40,801 |
) |
Swap |
|
Jan 2009 Dec 2009 |
|
|
30,000 |
|
|
$ |
7.35 |
|
|
$ |
(14,273 |
) |
|
|
|
* |
|
Unrealized losses are not adjusted for income tax effect. |
For the six months ended June 30, 2008, the Company recognized costs associated with
financially settled swaps to counterparties totaling $24.2 million as its net realization from
hedging activities, which was recognized as a reduction of natural gas sales on the income
statement.
ITEM 4 CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
22
We have 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). Our disclosure controls and procedures are the controls
and other procedures that we have designed to ensure that we record, process, accumulate and
communicate information to our
management, including our 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, our management, including our Chief Executive Officer and Chief Financial Officer,
concluded that our disclosure controls and procedures were effective as of June 30, 2008. There
were no changes in our internal control over financial reporting during the six months ended June
30, 2008 that have materially affected or are reasonably likely to affect, our internal control
over financial reporting.
PART II OTHER INFORMATION
ITEM 1. 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.
ITEM 1A. RISK FACTORS
There have been no material changes with respect to the risk factors disclosed in our Annual
Report on Form 10-K for the fiscal year ended December 31, 2007.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
On May 17, 2006, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $1 billion of the Companys outstanding common stock
which has been and will be funded by cash on hand and borrowings under the Companys senior credit
facility. Pursuant to this authorization, the Company has commenced a program to purchase up to
$500.0 million of the Companys outstanding shares through open market transactions or privately
negotiated transactions. (See Note 5 for further details).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number |
|
|
Maximum Number |
|
|
|
|
|
|
|
|
|
|
|
of Shares |
|
|
(or Approximate |
|
|
|
|
|
|
|
|
|
|
|
Purchased |
|
|
Dollar Value) |
|
|
|
|
|
|
|
|
|
|
|
as Part of |
|
|
of Shares That |
|
|
|
|
|
|
|
|
|
|
|
Publicly |
|
|
May Yet be |
|
|
|
Total Number |
|
|
Average |
|
|
Announced |
|
|
Purchased |
|
|
|
of Shares |
|
|
Price Paid |
|
|
Plans or |
|
|
Under the |
|
Period |
|
Purchased |
|
|
per Share |
|
|
Programs |
|
|
Plans or Programs |
|
Jan 1 Jan 31, 2008 |
|
|
96,321 |
|
|
$ |
71.57 |
|
|
|
96,321 |
|
|
$699 million |
Feb 1 Feb 28, 2008 |
|
|
71,281 |
|
|
$ |
79.04 |
|
|
|
71,281 |
|
|
$693 million |
Mar 1 Mar 31, 2008 |
|
|
228,830 |
|
|
$ |
75.61 |
|
|
|
228,830 |
|
|
$676 million |
Apr 1 Apr 30, 2008 |
|
|
223,559 |
|
|
$ |
79.51 |
|
|
|
223,559 |
|
|
$658 million |
May 1 May 31, 2008 |
|
|
45,668 |
|
|
$ |
90.07 |
|
|
|
45,668 |
|
|
$654 million |
Jun 1 Jun 30, 2008 |
|
|
182,153 |
|
|
$ |
92.88 |
|
|
|
182,153 |
|
|
$637 million |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
847,812 |
|
|
$ |
80.96 |
|
|
|
847,812 |
|
|
$637 million |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to June 30, 2008 and through July 31, 2008, the Company has repurchased $67.8
million of its outstanding common stock in open market repurchases or net share settlements.
ITEM 3. DEFAULTS IN SENIOR SECURITIES
23
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS |
The Company held its annual meeting on May 16, 2008. At the annual meeting, the entire board
of directors of the Company was elected. The votes cast for each of the directors proposed by the
Companys definitive proxy statement on Schedule 14A was as follows:
|
|
|
|
|
Michael D. Watford
|
|
|
|
134,031,245 voted in favor, zero voted against and 839,676 withheld. |
|
W. Charles Helton
|
|
|
|
134,499,794 voted in favor, zero voted against and 371,127 withheld. |
|
Stephen J. McDaniel
|
|
|
|
133,826,892 voted in favor, zero voted against and 1,044,029 withheld. |
|
Roger A. Brown
|
|
|
|
133,828,182 voted in favor, zero voted against and 1,042,739 withheld. |
|
Robert E. Rigney
|
|
|
|
134,542,847 voted in favor, zero voted against and 328,074 withheld. |
The shareholders of the Company approved the appointment of Ernst & Young, LLP as the
Companys independent auditors for 2008. There were 134,582,266 votes in favor of approval of the
appointment of Ernst & Young, LLP as the Companys auditors, zero votes against and 288,654 votes
withheld.
The shareholders of the Company voted against the shareholder proposal regarding climate
change with 67,584,431 votes against, 38,958,528 votes in favor of the proposal and 28,327,962
Broker Non-votes.
A total of 134,870,921 shares were voted by 221 shareholders, representing 88% of the
Companys outstanding shares.
ITEM 5. OTHER INFORMATION
None.
24
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K -
(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.) |
|
|
|
10.1
|
|
Master Note Purchase Agreement dated March 6, 2008 (incorporated by
reference to Exhibit 10.1 of the Companys Report on Form 8-K filed
on March 6, 2008). |
|
|
|
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. |
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
ULTRA PETROLEUM CORP.
|
|
|
By: |
/s/ Michael D. Watford
|
|
|
|
Name: |
Michael D. Watford |
|
|
|
Title: |
Chairman, President and Chief Executive Officer |
|
|
Date: August 6, 2008
|
|
|
|
|
|
|
|
|
By: |
/s/ Marshall D. Smith
|
|
|
|
Name: |
Marshall D. Smith |
|
|
|
Title: |
Chief Financial Officer |
|
|
Date: August 6, 2008
26
EXHIBIT INDEX
|
|
|
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). |
|
|
|
10.1
|
|
Master Note Purchase Agreement dated March 6, 2008 (incorporated
by reference to Exhibit 10.1 of the Companys Report on Form 8-K
filed on March 6, 2008). |
|
|
|
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. |
27