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
September 30,
2010
|
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
001-33614
ULTRA PETROLEUM CORP.
(Exact name of registrant as
specified in its charter)
|
|
|
Yukon Territory, Canada
|
|
N/A
|
(State or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S. employer
identification number)
|
363 North Sam Houston Parkway,
|
|
77060
|
Suite 1200, Houston, Texas
|
|
(Zip code)
|
(Address of principal executive
offices)
|
|
|
(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 has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). YES 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
|
Smaller
reporting
company o
|
(Do not check if a smaller reporting company)
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 October 27, 2010 was
152,481,063.
PART I
FINANCIAL INFORMATION
|
|
ITEM 1
|
FINANCIAL
STATEMENTS
|
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands of U.S. dollars, except per share
data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
217,890
|
|
|
$
|
135,538
|
|
|
$
|
674,845
|
|
|
$
|
409,446
|
|
Oil sales
|
|
|
22,484
|
|
|
|
19,626
|
|
|
|
67,041
|
|
|
|
44,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
240,374
|
|
|
|
155,164
|
|
|
|
741,886
|
|
|
|
453,458
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
10,850
|
|
|
|
9,741
|
|
|
|
32,708
|
|
|
|
30,128
|
|
Production taxes
|
|
|
23,191
|
|
|
|
15,220
|
|
|
|
74,084
|
|
|
|
45,309
|
|
Gathering fees
|
|
|
12,616
|
|
|
|
11,389
|
|
|
|
37,069
|
|
|
|
33,753
|
|
Transportation charges
|
|
|
16,201
|
|
|
|
16,284
|
|
|
|
48,628
|
|
|
|
42,824
|
|
Depletion and depreciation
|
|
|
59,674
|
|
|
|
46,367
|
|
|
|
167,795
|
|
|
|
152,002
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,037,000
|
|
General and administrative
|
|
|
5,957
|
|
|
|
5,130
|
|
|
|
18,464
|
|
|
|
15,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
128,489
|
|
|
|
104,131
|
|
|
|
378,748
|
|
|
|
1,356,370
|
|
Operating income (loss)
|
|
|
111,885
|
|
|
|
51,033
|
|
|
|
363,138
|
|
|
|
(902,912
|
)
|
Other income (expense), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(11,382
|
)
|
|
|
(9,744
|
)
|
|
|
(34,538
|
)
|
|
|
(26,938
|
)
|
Gain (loss) on commodity derivatives
|
|
|
150,186
|
|
|
|
(55,428
|
)
|
|
|
346,103
|
|
|
|
90,301
|
|
Litigation expense
|
|
|
|
|
|
|
|
|
|
|
(9,902
|
)
|
|
|
|
|
Other income (expense), net
|
|
|
12
|
|
|
|
193
|
|
|
|
185
|
|
|
|
(2,925
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
138,816
|
|
|
|
(64,979
|
)
|
|
|
301,848
|
|
|
|
60,438
|
|
Income (loss) before income tax provision (benefit)
|
|
|
250,701
|
|
|
|
(13,946
|
)
|
|
|
664,986
|
|
|
|
(842,474
|
)
|
Income tax provision (benefit)
|
|
|
88,059
|
|
|
|
(5,616
|
)
|
|
|
238,477
|
|
|
|
(296,029
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
162,642
|
|
|
$
|
(8,330
|
)
|
|
$
|
426,509
|
|
|
$
|
(546,445
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
1.07
|
|
|
$
|
(0.06
|
)
|
|
$
|
2.80
|
|
|
$
|
(3.61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
1.05
|
|
|
$
|
(0.06
|
)
|
|
$
|
2.77
|
|
|
$
|
(3.61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic
|
|
|
152,479
|
|
|
|
151,441
|
|
|
|
152,286
|
|
|
|
151,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully
diluted
|
|
|
154,192
|
|
|
|
151,441
|
|
|
|
154,241
|
|
|
|
151,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
3
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Amounts in thousands of
|
|
|
|
U. S. dollars, except share data)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
7,218
|
|
|
$
|
14,254
|
|
Restricted cash
|
|
|
1,763
|
|
|
|
1,681
|
|
Oil and gas revenue receivable
|
|
|
68,112
|
|
|
|
82,326
|
|
Joint interest billing and other receivables
|
|
|
48,633
|
|
|
|
29,411
|
|
Derivative assets
|
|
|
161,312
|
|
|
|
4,398
|
|
Deferred tax assets
|
|
|
|
|
|
|
12,225
|
|
Inventory
|
|
|
4,731
|
|
|
|
4,498
|
|
Prepaid drilling costs and other current assets
|
|
|
8,610
|
|
|
|
4,948
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
300,379
|
|
|
|
153,741
|
|
Oil and gas properties, net, using the full cost method of
accounting:
|
|
|
|
|
|
|
|
|
Proved
|
|
|
2,337,853
|
|
|
|
1,794,603
|
|
Unproved properties not being amortized
|
|
|
469,243
|
|
|
|
|
|
Property, plant and equipment
|
|
|
133,054
|
|
|
|
73,435
|
|
Long-term derivative assets
|
|
|
28,600
|
|
|
|
2,554
|
|
Restricted cash
|
|
|
|
|
|
|
28,257
|
|
Deferred financing costs and other
|
|
|
5,964
|
|
|
|
7,415
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,275,093
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
181,234
|
|
|
$
|
131,122
|
|
Production taxes payable
|
|
|
45,657
|
|
|
|
60,820
|
|
Deferred tax liabilities
|
|
|
54,812
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
35,033
|
|
Capital cost accrual
|
|
|
124,144
|
|
|
|
64,216
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
405,847
|
|
|
|
291,191
|
|
Long-term debt
|
|
|
1,326,000
|
|
|
|
795,000
|
|
Deferred income tax liabilities
|
|
|
386,730
|
|
|
|
239,217
|
|
Long-term derivative liabilities
|
|
|
|
|
|
|
50,542
|
|
Other long-term obligations
|
|
|
63,980
|
|
|
|
35,858
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Common stock no par value; authorized
unlimited; issued and outstanding 152,479,188 and
151,759,343 at September 30, 2010 and December 31,
2009, respectively
|
|
|
418,287
|
|
|
|
377,339
|
|
Treasury stock
|
|
|
|
|
|
|
(10,525
|
)
|
Retained earnings
|
|
|
674,249
|
|
|
|
281,383
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
1,092,536
|
|
|
|
648,197
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity
|
|
$
|
3,275,093
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
4
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands
|
|
|
|
of U.S. dollars)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss) for the period
|
|
$
|
426,509
|
|
|
$
|
(546,445
|
)
|
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
167,795
|
|
|
|
152,002
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
Deferred income taxes
|
|
|
230,936
|
|
|
|
(303,724
|
)
|
Unrealized (gain) loss on commodity derivatives
|
|
|
(268,535
|
)
|
|
|
118,879
|
|
Excess tax benefit from stock based compensation
|
|
|
(16,386
|
)
|
|
|
(4,966
|
)
|
Stock compensation
|
|
|
9,122
|
|
|
|
7,623
|
|
Other
|
|
|
473
|
|
|
|
881
|
|
Net changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(82
|
)
|
|
|
1,044
|
|
Accounts receivable
|
|
|
(5,008
|
)
|
|
|
9,774
|
|
Prepaid expenses and other
|
|
|
(3,236
|
)
|
|
|
2,740
|
|
Other current and non-current assets
|
|
|
2,905
|
|
|
|
(4,584
|
)
|
Accounts payable, production taxes and accrued liabilities
|
|
|
36,264
|
|
|
|
(40,898
|
)
|
Other long-term obligations
|
|
|
20,562
|
|
|
|
(8,557
|
)
|
Taxation payable
|
|
|
2,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
604,144
|
|
|
|
420,769
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
|
(400,993
|
)
|
|
|
|
|
Oil and gas property expenditures
|
|
|
(831,423
|
)
|
|
|
(500,211
|
)
|
Gathering system expenditures
|
|
|
(61,343
|
)
|
|
|
(36,747
|
)
|
Restricted cash
|
|
|
28,257
|
|
|
|
|
|
Change in capital cost accrual
|
|
|
59,928
|
|
|
|
(52,055
|
)
|
Net proceeds from consolidation of undeveloped land
|
|
|
68,420
|
|
|
|
|
|
Inventory
|
|
|
(233
|
)
|
|
|
3,759
|
|
Other
|
|
|
|
|
|
|
(703
|
)
|
Purchase of capital assets
|
|
|
(769
|
)
|
|
|
(932
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(1,138,156
|
)
|
|
|
(586,889
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
Borrowings on long-term debt
|
|
|
986,000
|
|
|
|
575,000
|
|
Payments on long-term debt
|
|
|
(955,000
|
)
|
|
|
(650,000
|
)
|
Proceeds from issuance of Senior Notes
|
|
|
500,000
|
|
|
|
235,000
|
|
Deferred financing costs
|
|
|
(2,265
|
)
|
|
|
(1,283
|
)
|
Repurchased shares/net share settlements
|
|
|
(23,707
|
)
|
|
|
|
|
Excess tax benefit from stock based compensation
|
|
|
16,386
|
|
|
|
4,966
|
|
Proceeds from exercise of options
|
|
|
5,562
|
|
|
|
1,274
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
526,976
|
|
|
|
164,957
|
|
Decrease in cash during the period
|
|
|
(7,036
|
)
|
|
|
(1,163
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
14,254
|
|
|
|
14,157
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
7,218
|
|
|
$
|
12,994
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
5
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All amounts in this Quarterly Report on
Form 10-Q
are expressed in thousands of U.S. dollars (except per
share data) unless otherwise noted)
DESCRIPTION
OF THE BUSINESS:
Ultra Petroleum Corp. (the Company) is an
independent oil and gas company engaged in the development,
production, operation, exploration and acquisition of oil and
natural gas properties. The Company is incorporated under the
laws of the Yukon Territory, Canada. The Companys
principal business activities are conducted in the Green River
Basin of Southwest Wyoming and in the north-central Pennsylvania
area of the Appalachian Basin.
|
|
1.
|
SIGNIFICANT
ACCOUNTING POLICIES:
|
The accompanying financial statements, other than the balance
sheet data as of December 31, 2009, are unaudited and were
prepared from the Companys records, but do not include all
disclosures required by U.S. Generally Accepted Accounting
Principles (GAAP). Balance sheet data as of
December 31, 2009 was derived from the Companys
audited financial statements. The Companys management
believes that these financial statements include all adjustments
necessary for a fair presentation of the Companys
financial position and results of operations. All adjustments
are of a normal and recurring nature unless specifically noted.
The Company prepared these statements on a basis consistent with
the Companys annual audited statements and
Regulation S-X.
Regulation S-X
allows the Company to omit some of the footnote and policy
disclosures required by generally accepted accounting principles
and normally included in annual reports on
Form 10-K.
You should read these interim financial statements together with
the financial statements, summary of significant accounting
policies and notes to the Companys most recent annual
report on
Form 10-K.
Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries. The Company presents its financial
statements in accordance with U.S. GAAP. All inter-company
transactions and balances have been eliminated upon
consolidation.
(a) Cash and cash equivalents: The
Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
(b) Restricted cash: Restricted cash
represents cash received by the Company from production sold
where the final division of ownership of the production is
unknown or in dispute.
Long-term restricted cash at December 31, 2009 represents
cash that was set aside in an escrow account in connection with
the purchase of additional acreage in the Marcellus Shale, which
closed on February 22, 2010.
(c) Property, plant and
equipment: Capital assets are recorded at cost
and depreciated using the declining-balance method based on a
seven-year useful life. Gathering system expenditures are
recorded at cost and depreciated using the straight-line method
based on a
30-year
useful life.
(d) Oil and natural gas properties: On
January 6, 2010, the Financial Accounting Standards Board
(FASB) issued an Accounting Standards Update
(ASU), Oil and Gas Reserve Estimation and
Disclosures. The ASU amends FASB Accounting Standards
Codification (ASC) Topic 932, Extractive
Activities Oil and Gas (FASB
ASC 932) to align the reserve calculation and
disclosure requirements of FASB ASC 932 with the
requirements in the SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting Requirements (SEC
Release
No. 33-8995).
The ASU was effective for reporting periods ending on or after
December 31, 2009. Accordingly, the Company adopted the
update to FASB ASC 932 as of December 31, 2009.
6
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses the full cost method of accounting for
exploration and development activities as defined by the
Securities and Exchange Commission (SEC). 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 reserves and production
are converted into equivalent units based on relative energy
content. Asset retirement obligations are included in the base
costs for calculating depletion.
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
results in a lower DD&A rate in future periods. A
write-down may not be reversed in future periods even though
higher oil and natural gas prices may subsequently increase the
ceiling.
(e) Inventories: Materials and supplies
inventories are carried at 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 September 30, 2010,
drilling and completion supplies inventory of $4.7 million
primarily included the cost of pipe and production equipment
that are expected to be utilized during the 2010 and 2011
drilling programs.
(f) Derivative Instruments and Hedging
Activities: Currently, the Company largely relies
on derivative instruments to manage its exposure to commodity
price risk. The natural gas reference prices of the
Companys commodity derivative contracts are typically
referenced to natural gas index prices as published by
independent third parties. Additionally, and from time to time,
the Company enters into fixed price forward gas sales agreements
in order to mitigate its commodity price exposure on a portion
of its natural gas production. These fixed price forward gas
sales are considered normal sales in the ordinary course of
business and outside the scope of FASB ASC Topic 815,
Derivatives and Hedging (FASB ASC 815). The
Company does not offset the value of its derivative arrangements
with the same counterparty. (See Note 7).
(g) 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
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
operating loss and tax credit carryforwards. Deferred tax assets
and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the
enactment date. Valuation allowances are recorded related to
deferred tax assets based on the more likely than
not criteria described in FASB ASC Topic 740, Income
Taxes. In addition, 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.
(h) Earnings per share: Basic earnings
per share is computed by dividing net earnings attributable to
common stockholders by the weighted average number of common
shares outstanding during each period. Diluted earnings per
share is computed by adjusting the average number of common
shares outstanding for the dilutive effect, if any, of common
stock equivalents. The Company uses the treasury stock method to
determine the dilutive effect.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Net income (loss)
|
|
$
|
162,642
|
|
|
$
|
(8,330
|
)
|
|
$
|
426,509
|
|
|
$
|
(546,445
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic
|
|
|
152,479
|
|
|
|
151,441
|
|
|
|
152,286
|
|
|
|
151,337
|
|
Effect of dilutive instruments(1)
|
|
|
1,713
|
|
|
|
|
|
|
|
1,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully
diluted
|
|
|
154,192
|
|
|
|
151,441
|
|
|
|
154,241
|
|
|
|
151,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
1.07
|
|
|
$
|
(0.06
|
)
|
|
$
|
2.80
|
|
|
$
|
(3.61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
1.05
|
|
|
$
|
(0.06
|
)
|
|
$
|
2.77
|
|
|
$
|
(3.61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Due to the net loss for the quarter and nine months ended
September 30, 2009, 2.9 million and 2.8 million
shares, respectively, for options and restricted stock were
anti-dilutive and excluded from the computation of loss per
share. |
(i) Use of estimates: Preparation of
consolidated financial statements in accordance with
U.S. GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
(j) Accounting for share-based
compensation: The Company measures and recognizes
compensation expense for all share-based payment awards made to
employees and directors, including employee stock options, based
on estimated fair values in accordance with FASB ASC Topic 718,
Compensation Stock Compensation.
(k) Fair Value Accounting: The Company
follows FASB ASC Topic 820, Fair Value Measurements and
Disclosures (FASB ASC 820), which defines fair
value, establishes a framework for measuring fair value in
generally accepted accounting principles, and describes
disclosures about fair value measurements. This statement
applies under other accounting topics that require or permit
fair value measurements. For non-financial assets and
liabilities measured or disclosed at fair value on a
non-recurring basis, primarily our asset retirement obligation,
the respective subtopic of FASB ASC 820, was effective
January 1, 2009.
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Implementation of this portion of the standard did not have a
material impact on consolidated results of operations, financial
position or liquidity. See Note 8 for additional
information.
(l) Asset Retirement Obligation: The
initial estimated retirement obligation of properties is
recognized as a liability with an associated increase in oil and
gas properties for the asset retirement cost. Accretion expense
is recognized over the estimated productive life of the related
assets. If the fair value of the estimated asset retirement
obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions
in estimated liabilities can result from revisions of estimated
inflation rates, changes in service and equipment costs and
changes in the estimated timing of settling asset retirement
obligations.
(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) Capitalized Interest: Interest is
capitalized on the cost of unevaluated gas and oil properties
that are excluded from amortization and actively being evaluated
as well as on work in process relating to gathering systems that
are not currently in service.
(o) Reclassifications: Certain amounts in
the financial statements of prior periods have been reclassified
to conform to the current period financial statement
presentation.
|
|
2.
|
OTHER
COMPREHENSIVE INCOME:
|
Other comprehensive income (loss) is a term used to define
revenues, expenses, gains and losses that under generally
accepted accounting principles impact Shareholders Equity,
excluding transactions with shareholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Net income (loss)
|
|
$
|
162,642
|
|
|
$
|
(8,330
|
)
|
|
$
|
426,509
|
|
|
$
|
(546,445
|
)
|
Reclassification for settlements of derivative instruments*
|
|
|
|
|
|
|
(5,960
|
)
|
|
|
|
|
|
|
(18,520
|
)
|
Tax expense on settlements of derivative instruments
|
|
|
|
|
|
|
2,092
|
|
|
|
|
|
|
|
6,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
$
|
162,642
|
|
|
$
|
(12,198
|
)
|
|
$
|
426,509
|
|
|
$
|
(558,465
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet (See
Note 7). The net gain or loss in accumulated other
comprehensive income at November 3, 2008 remained on the
balance sheet and the respective months gains or losses
were reclassified from accumulated other comprehensive income to
earnings as the counterparty settlements affected earnings
(January through December 2009). As a result of the
de-designation on November 3, 2008, the Company no longer
has any derivative instruments which qualify for cash flow hedge
accounting. |
9
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
3.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
4,251,496
|
|
|
$
|
3,544,519
|
|
Less: Accumulated depletion, depreciation and amortization
|
|
|
(1,913,643
|
)
|
|
|
(1,749,916
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
2,337,853
|
|
|
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized(1)(2)
|
|
|
469,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs oil and gas properties
|
|
$
|
2,807,096
|
|
|
$
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In 2010, a wholly-owned subsidiary of the Company acquired, for
$401.0 million in cash, non-producing mineral acres and a
small number of producing gas wells in the Pennsylvania
Marcellus Shale. Additionally, during the second quarter of
2010, the Company purchased additional undeveloped acreage in
the Marcellus Shale for approximately $60.1 million. |
|
(2) |
|
Interest is capitalized on the cost of unevaluated oil and
natural gas properties that are excluded from amortization and
actively being evaluated as well as on work in process relating
to gathering systems that are not currently in service. For the
nine months ended September 30, 2010, total interest on
outstanding debt was $48.4 million of which,
$13.9 million was capitalized on the cost of unevaluated
oil and natural gas properties and work in process relating to
gathering systems that are not currently in service. For the
nine months ended September 30, 2009, there was no interest
capitalized. |
|
|
4.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Bank indebtedness
|
|
$
|
291,000
|
|
|
$
|
260,000
|
|
Senior Notes
|
|
|
1,035,000
|
|
|
|
535,000
|
|
Other long-term obligations
|
|
|
63,980
|
|
|
|
35,858
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,389,980
|
|
|
$
|
830,858
|
|
|
|
|
|
|
|
|
|
|
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 the Companys 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 the Companys consolidated
leverage ratio (125.0 basis points per annum as of
September 30, 2010).
At September 30, 2010, the Company had $291.0 million
in outstanding borrowings and $209.0 million of available
borrowing capacity under the credit facility.
10
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 three and one half times; and as long as
the Companys debt rating is below investment grade, the
maintenance of an annual ratio of the net present value of the
Companys oil and gas properties to total funded debt of at
least 1.75 to 1.00. At September 30, 2010, the Company was
in compliance with all of its debt covenants under the credit
facility.
Senior Notes: On January 28, 2010, Ultra
Resources, Inc., issued $500.0 million of Senior Notes
(the 2010A Senior Notes) pursuant to a Second
Supplement to the Master Note Purchase Agreement between the
Company and the purchasers of the Notes. The Senior Notes rank
pari passu with the Companys bank credit facility. Payment
of the Senior Notes is guaranteed by Ultra Petroleum Corp. and
UP Energy Corporation.
The Senior Notes are pre-payable in whole or in part at any time
and are subject to representations, warranties, covenants and
events of default customary for a senior note financing. At
September 30, 2010, the Company was in compliance with all
of its debt covenants under the Master Note Purchase Agreement.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable and asset retirement obligations.
|
|
5.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
Ended September 30,
|
|
Ended September 30,
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Total cost of share-based payment plans
|
|
$
|
4,778
|
|
|
$
|
4,814
|
|
|
$
|
15,273
|
|
|
$
|
13,247
|
|
Amounts capitalized in fixed assets
|
|
$
|
1,793
|
|
|
$
|
2,009
|
|
|
$
|
6,151
|
|
|
$
|
5,624
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
2,985
|
|
|
$
|
2,805
|
|
|
$
|
9,122
|
|
|
$
|
7,623
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
1,060
|
|
|
$
|
985
|
|
|
$
|
3,238
|
|
|
$
|
2,676
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model. 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 estimates 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-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. There were no stock options
granted during the nine months ended September 30, 2010 or
2009.
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the nine months ended September 30, 2010 and the year ended
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
|
Options
|
|
|
Exercise Price
|
|
|
|
(000s)
|
|
|
(US$)
|
|
|
Balance, December 31, 2008
|
|
|
4,213
|
|
|
$
|
0.25 to $98.87
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(43
|
)
|
|
$
|
51.60 to $78.55
|
|
Exercised
|
|
|
(666
|
)
|
|
$
|
0.25 to $33.57
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
3,504
|
|
|
$
|
1.49 to $98.87
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(67
|
)
|
|
$
|
51.60 to $76.01
|
|
Exercised
|
|
|
(1,117
|
)
|
|
$
|
1.49 to $45.95
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2010
|
|
|
2,320
|
|
|
$
|
2.61 to $98.87
|
|
|
|
|
|
|
|
|
|
|
PERFORMANCE
SHARE PLANS:
Long Term Incentive Plans. Each year since
2005, the Company has adopted a Long Term Incentive Plan
(LTIP) in order to further align the interests of
key employees with shareholders and to give key employees the
opportunity to share in the long-term performance of the Company
when specific corporate financial and operational goals are
achieved. Each LTIP covers a performance period of three years.
The 2008 LTIP has two components: an LTIP Stock Option
Award and an LTIP Common Stock Award. In 2009
and 2010, the Compensation Committee (the Committee)
approved an award consisting only of performance-based
restricted stock units to be awarded to each participant.
Under each LTIP, the Compensation Committee establishes a
percentage of base salary for each participant which is
multiplied by the participants base salary to derive a
Long Term Incentive Value. The LTIP Common Stock Award in 2008
and the 2009 and 2010 LTIP award of restricted stock units are
performance-based and are measured over a three year performance
period. For each LTIP award, the Compensation Committee
establishes performance measures at the beginning of each
performance period, and each participant is assigned threshold
and maximum award levels in the event that actual performance is
below or above target levels. For the 2008, 2009 and 2010 LTIP
awards, the Committee established the following performance
measures: return on equity, reserve replacement ratio, and
production growth.
For the nine months ended September 30, 2010, the Company
recognized $5.9 million in pre-tax compensation expense
related to the 2008 LTIP Common Stock Award and 2009 and 2010
LTIP award of restricted stock units. For the nine months ended
September 30, 2009, the Company recognized
$3.9 million in pre-tax compensation expense related to the
2007 and 2008 LTIP Common Stock Awards and the 2009 LTIP award
of restricted stock units. The amounts recognized during the
nine months ended September 30, 2010 assumes that maximum
performance objectives are attained. If the Company ultimately
attains these performance objectives, the associated total
compensation, estimated at September 30, 2010, for each of
the three year performance periods is expected to be
approximately $4.3 million, $22.8 million, and
$11.2 million related to the 2008 LTIP Common Stock Award
and 2009 and 2010 LTIP award of restricted stock units,
respectively. The 2007 LTIP Common Stock Award was paid in
shares of the Companys stock to employees during the first
quarter of 2010 and totaled $4.1 million.
Best in Class Program. In May 2008, the
Company established the 2008 Best in Class Program for all
permanent, full-time employees. Under the 2008 Best in
Class Program, participants are eligible to receive a
number of shares of the Companys common stock based on the
performance of the Company. As with the
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
LTIP, the 2008 Best in Class Program is measured over a
three year performance period. The 2008 Best in
Class Program recognizes and financially rewards the
collective efforts of all of the Companys employees in
achieving sustained industry leading performance and the
enhancement of shareholder value. Under the 2008 Best in
Class Program, on January 1, 2008 or the employment
date if subsequent to January 1, 2008, eligible employees
received a contingent award of stock units of the Companys
common stock based on the average high and low share price on
the first day of the performance period. Employees joining the
Company after January 1, 2008 participate on a pro-rata
basis based on their length of employment during the performance
period.
The number of contingent units that will become payable and vest
upon distribution is based on the Companys performance
relative to the industry during a three year performance period
beginning January 1, 2008, and ending December 31,
2010. For each vested unit, the participant will receive one
share of common stock. The participant must be employed on the
date the awards are distributed in order to receive the award.
For the nine months ended September 30, 2010, the Company
recognized $0.9 million in pre-tax compensation expense
related to the 2008 Best in Class Program. For the nine
months ended September 30, 2009, the Company recognized
$0.6 million in pre-tax compensation expense related to the
2008 Best in Class Program. The amount recognized for the
nine months ended September 30, 2010 assumes that target
performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total
compensation related to the 2008 Best in Class Program is
estimated at $4.8 million as of September 30, 2010.
During the quarter ended September 30, 2010, the Company
recorded an income tax provision of $88.1 million, or 35.1%
of income before income tax provision. This compares to an
income tax benefit of $5.6 million, or 40.3% of the loss
before income tax benefit for the quarter ended
September 30, 2009. The effective tax rate decreased over
the comparable prior year period primarily due certain
reconciling items related to the filing of the 2008
U.S. Income Tax return in the third quarter of 2009.
During the nine months ended September 30, 2010, the
Company recorded an income tax provision of $238.5 million,
or 35.9% of income before income tax provision. This compares to
an income tax benefit of $296.0 million, or 35.1% of the
loss before income tax benefit for the nine months ended
September 30, 2009. The effective tax rate increased over
the comparable prior year period primarily due to elevated
activity levels in the higher state tax rate jurisdiction of
Pennsylvania. A one-time
catch-up was
required during the first quarter of 2010 which caused the
effective tax rate for the nine months ended September 30,
2010 to increase.
|
|
7.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
natural gas production. Historically, prices received for
natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was
13
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effective upon entering into these transactions in March 2009,
with upcoming settlements for production months through December
2010. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas
index prices as published by independent third parties.
From time to time, the Company may use fixed price forward gas
sales to manage its commodity price exposure. These fixed price
forward gas sales are considered normal sales in the ordinary
course of business and outside the scope of FASB ASC 815,
Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At September 30, 2010, 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. See Note 8 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
Volume -
|
|
Average
|
|
September 30,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
6,473
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
79,746
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
10,000
|
|
|
$
|
6.27
|
|
|
$
|
8,288
|
|
Swap
|
|
NW Rockies
|
|
Oct 10
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
2,524
|
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
25,740
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
165,000
|
|
|
$
|
5.71
|
|
|
$
|
67,141
|
|
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the nine months and quarters ended
September 30, 2010 and 2009 (refer to Note 2 for
details of unrealized gains or losses included in accumulated
other comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
40,583
|
|
|
$
|
89,620
|
|
|
$
|
77,568
|
|
|
$
|
209,180
|
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
|
109,603
|
|
|
|
(145,048
|
)
|
|
|
268,535
|
|
|
|
(118,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on commodity derivatives
|
|
$
|
150,186
|
|
|
$
|
(55,428
|
)
|
|
$
|
346,103
|
|
|
$
|
90,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain (loss) on commodity derivatives in the
Consolidated Statements of Operations. |
14
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
8.
|
FAIR
VALUE MEASUREMENTS:
|
As required by the Fair Value Measurements and Disclosure Topic
of the FASB Accounting Standards Codification, we define fair
value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between
market participants at the measurement date and establishes a
three level hierarchy for measuring fair value. Fair value
measurements are classified and disclosed in one of the
following categories:
|
|
|
Level 1:
|
|
Quoted prices (unadjusted) in active markets for identical
assets and liabilities that 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 commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level the
Companys assets and liabilities, including both current
and non-current portions, measured at fair value on a recurring
basis, as of September 30, 2010. The company has no
derivative instruments which qualify for cash flow hedge
accounting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
161,312
|
|
|
$
|
|
|
|
$
|
161,312
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
28,600
|
|
|
$
|
|
|
|
$
|
28,600
|
|
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
For non-financial assets and liabilities measured or disclosed
at fair value on a non-recurring basis, primarily the
Companys asset retirement obligation, this respective
subtopic of FASB ASC 820 was effective January 1,
2009. Implementation of this portion of the standard did not
have a material impact on the Companys consolidated
results of operations, financial position or liquidity.
15
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value of Financial Instruments
The estimated fair value of financial instruments is the amount
at which the instrument could be exchanged currently between
willing parties. The carrying amounts reported in the
consolidated balance sheet for cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value
due to the immediate or short-term maturity of these financial
instruments. We use available market data and valuation
methodologies to estimate the fair value of debt. This
disclosure is presented in accordance with FASB ASC Topic 825,
Financial Instruments, and does not impact the Companys
financial position, results of operations or cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010
|
|
|
December 31, 2009
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.45% Notes due 2015, issued 2008
|
|
$
|
100,000
|
|
|
$
|
110,998
|
|
|
$
|
100,000
|
|
|
$
|
108,128
|
|
7.31% Notes due 2016, issued 2009
|
|
|
62,000
|
|
|
|
74,867
|
|
|
|
62,000
|
|
|
|
72,684
|
|
4.98% Notes due 2017, issued 2010
|
|
|
116,000
|
|
|
|
125,834
|
|
|
|
|
|
|
|
|
|
5.92% Notes due 2018, issued 2008
|
|
|
200,000
|
|
|
|
227,443
|
|
|
|
200,000
|
|
|
|
212,946
|
|
7.77% Notes due 2019, issued 2009
|
|
|
173,000
|
|
|
|
219,269
|
|
|
|
173,000
|
|
|
|
205,609
|
|
5.50% Notes due 2020, issued 2010
|
|
|
207,000
|
|
|
|
227,030
|
|
|
|
|
|
|
|
|
|
5.60% Notes due 2022, issued 2010
|
|
|
87,000
|
|
|
|
94,615
|
|
|
|
|
|
|
|
|
|
5.85% Notes due 2025, issued 2010
|
|
|
90,000
|
|
|
|
96,718
|
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
|
291,000
|
|
|
|
291,000
|
|
|
|
260,000
|
|
|
|
260,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,326,000
|
|
|
$
|
1,467,774
|
|
|
$
|
795,000
|
|
|
$
|
859,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
FASB ASC Topic 855, Subsequent Events (FASB
ASC 855), sets forth principles and requirements to
be applied to the accounting for and disclosure of subsequent
events. FASB ASC 855 sets forth the period after the
balance sheet date during which management shall evaluate events
or transactions that may occur for potential recognition or
disclosure in the financial statements, the circumstances under
which events or transactions occurring after the balance sheet
date shall be recognized in the financial statements and the
required disclosures about events or transactions that occurred
after the balance sheet date. The FASB issued ASU No
2010-09,
Subsequent Events - Amendments to Certain Recognition and
Disclosure Requirements, on February 24, 2010, in an effort
to remove some contradictions between the requirements of
U.S. GAAP and the SECs filing rules. The amendments
remove the requirement that public companies disclose the date
of their financial statements in both issued and revised
financial statements. The Company has evaluated the period
subsequent to September 30, 2010 for events that did not
exist at the balance sheet date but arose after that date and
determined that the subsequent event described below should be
disclosed in order to keep the financial statements from being
misleading.
16
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On October 12, 2010, the Companys subsidiary, Ultra
Resources, Inc., issued $525.0 million of Senior Notes (the
2010B Senior Notes) pursuant to a Third Supplement
to its Master Note Purchase Agreement dated March 6, 2008.
The 2010B Senior Notes rank pari passu with Ultra
Resources bank revolving credit facility and other
outstanding Senior Notes. Payment of the 2010B Senior Notes is
guaranteed by the Company and its subsidiary, UP Energy
Corporation. A portion of the proceeds from the 2010B Senior
Notes was used to repay revolving credit facility debt, but did
not reduce the borrowings available under the revolving credit
facility, and the balance will be used for general corporate
purposes. Of the 2010B Senior Notes, $315.0 million are
4.51% senior notes due in 2020, $35.0 million are
4.66% senior notes due in 2022 and $175.0 million are
4.91% senior notes due in 2025.
17
|
|
ITEM 2
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the 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.
The Company currently generates substantially all of its
revenue, earnings and cash flow from the production and sales of
natural gas and oil. The price of natural gas is a critical
factor to the Companys business and the price of natural
gas has historically been volatile. 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 and swap agreements for natural gas. During the
quarter ended September 30, 2010, the average price
realization for the Companys natural gas was $4.84 per
Mcf, including realized gains and losses on commodity
derivatives. The Companys average price realization for
natural gas was $4.08 per Mcf, excluding the realized gains and
losses on commodity derivatives. (See Note 7).
The Company has consistently delivered meaningful reserve and
production growth over the past ten years and management
believes it has the ability to continue growing production by
drilling already identified locations on its core properties.
Ultra maintains a portfolio of properties that provide long-term
growth through development in areas that support sustainable,
lower-risk, repeatable, high return drilling projects. The
Company delivered 21% production growth on an Mcfe basis during
the quarter ended September 30, 2010 as compared to the
same quarter in 2009.
The Company currently conducts operations exclusively in the
United States. Substantially all of the oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented 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.
Derivative Instruments and Hedging
Activities. Currently, the Company largely relies
on derivative instruments to manage its exposure to commodity
price risk. The natural gas reference prices of the
Companys commodity derivative contracts are typically
referenced to natural gas index prices as published by
independent third parties. Additionally, and from time to time,
the Company enters into fixed price forward gas sales agreements
in order to mitigate its commodity price exposure on a portion
of its natural gas production. These fixed price forward gas
sales are considered normal sales in the ordinary course of
business and outside the scope of FASB ASC Topic 815,
Derivatives and Hedging (FASB ASC 815).
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The
Company previously followed hedge accounting for its natural gas
hedges. Under this prior accounting method, the unrealized gain
or loss on qualifying cash flow hedges (calculated on a mark to
market basis, net of tax) was recorded on the balance sheet in
stockholders equity as accumulated other comprehensive
income (loss). When an unrealized hedging gain or loss was
realized upon contract expiration, it was reclassified into
earnings through inclusion in natural gas sales revenues. The
Company continues to record the fair value of its commodity
derivatives as an asset or liability on the Consolidated Balance
Sheets, but records the changes in the fair value of its
commodity derivatives in the Consolidated Statements of
Operations as an unrealized gain or loss on commodity
derivatives.
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provides operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010.
18
Fair Value Measurements. The Company follows
FASB ASC Topic 820, Fair Value Measurements and Disclosures
(FASB ASC 820). Under FASB ASC 820, fair
value is defined as the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction
between market participants at measurement date and establishes
a three level hierarchy for measuring fair value. The valuation
assumptions utilized to measure the fair value of the
Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance
with the requirements of FASB ASC 820 and we aligned the
categories below with the Level 1, 2, and 3 fair value
measurements as defined by the Fair Value Measurements and
Disclosures Topic. The balance of net unrealized gains and
losses recognized for the Companys energy-related
derivative instruments at September 30, 2010 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
161,312
|
|
|
$
|
|
|
|
$
|
161,312
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
28,600
|
|
|
$
|
|
|
|
$
|
28,600
|
|
|
|
|
(a) |
|
Values represent observable unadjusted quoted prices for traded
instruments in active markets. |
|
(b) |
|
Values with inputs that are observable directly or indirectly
for the instrument, but do not qualify for Level 1. |
|
(c) |
|
Values with a significant amount of inputs that are not
observable for the instrument. |
Asset Retirement Obligation. The
Companys asset retirement obligations (ARO)
consist primarily of estimated costs of dismantlement, removal,
site reclamation and similar activities associated with its oil
and natural gas properties. FASB ASC Topic 410, Asset Retirement
and Environmental Obligations (FASB ASC 410)
requires that the discounted fair value of a liability for an
ARO be recognized in the period in which it is incurred with the
associated asset retirement cost capitalized as part of the
carrying cost of the oil and natural gas asset. The recognition
of an ARO requires that management make numerous estimates,
assumptions and judgments regarding such factors as the
existence of a legal obligation for an ARO, estimated
probabilities, amounts and timing of settlements; the
credit-adjusted, risk-free rate to be used; inflation rates, and
future advances in technology. In periods subsequent to initial
measurement of the ARO, the Company must recognize
period-to-period
changes in the liability resulting from the passage of time and
revisions to either the timing or the amount of the original
estimate of undiscounted cash flows. Increases in the ARO
liability due to passage of time impact net income as accretion
expense. The related capitalized costs, including revisions
thereto, are charged to expense through depletion, depreciation
and amortization (DD&A).
Share-Based Payment Arrangements. The Company
applies FASB ASC Topic 718, Compensation Stock
Compensation (FASB ASC 718), which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair
values. Share-based compensation expense recognized for the nine
months ended September 30, 2010 and 2009 was
$9.1 million and $7.6 million, respectively. At
September 30, 2010, there was $1.2 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 0.51 years. See Note 5 for additional information.
19
FASB ASC 718 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 period 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.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
results in a lower DD&A rate in future periods. A
write-down may not be reversed in future periods even though
higher oil and natural gas prices may subsequently increase the
ceiling.
The Company did not have any write-downs related to the full
cost ceiling limitation during the nine months ended
September 30, 2010. During the first quarter of 2009, the
Company recorded a $1.0 billion ($673.0 million net of
tax) non-cash write-down of the carrying value of the
Companys proved oil and gas properties as of
March 31, 2009, as a result of the ceiling test limitation,
which is reflected as write-down of proved oil and gas
properties in the accompanying consolidated statements of
operations. The March 31, 2009 ceiling test limitation was
calculated prior to the adoption of SEC Release
No. 33-8995
and was based on prices in effect on the last day of the
reporting period, March 31, 2009, reflecting wellhead
prices of $2.47 per Mcf for natural gas and $33.91 per barrel
for condensate.
The calculation of the ceiling test is based upon estimates of
proved reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves, in projecting the
future rates of production and in the timing of development
activities. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate
may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and
natural gas that are ultimately recovered.
Capitalized Interest. Interest is capitalized
on the cost of unevaluated gas and oil properties that are
excluded from amortization and actively being evaluated as well
as on work in process relating to gathering systems that are not
currently in service (See Note 3).
Conversion of barrels of oil to Mcfe of
gas. We convert Bbls of oil and other liquid
hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to
six Mcfe. This conversion ratio, which is typically used in the
oil and gas industry, represents the approximate energy
equivalent of a barrel of oil or other liquids to an Mcf of
natural gas. The sales price of one Bbl of oil or liquids has
been much higher than the sales price of six Mcf of natural gas
over the last several years, so a six to one conversion ratio
does not represent the economic equivalency of six Mcf of
natural gas to a Bbl of oil or other liquids.
20
RESULTS
OF OPERATIONS
QUARTER
ENDED SEPTEMBER 30, 2010 VS. QUARTER ENDED
SEPTEMBER 30, 2009
During the quarter ended September 30, 2010, production
increased 21% on a gas equivalent basis to 55.4 Bcfe from
45.9 Bcfe for the same quarter in 2009 attributable to the
Companys successful drilling activities during 2009 and in
the first nine months of 2010. Realized natural gas prices,
including realized gains and losses on commodity derivatives,
decreased 6% to $4.84 per Mcf in the third quarter of 2010 as
compared to $5.13 per Mcf for the same quarter of 2009. During
the three months ended September 30, 2010, the
Companys average price for natural gas was $4.08 per Mcf,
excluding realized gains and losses on commodity derivatives as
compared to $3.09 per Mcf for the same period in 2009. The
increase in production and the increase in average natural gas
prices, excluding commodity derivatives, contributed to a 55%
increase in revenues to $240.4 million as compared to
$155.2 million in 2009.
Lease operating expense (LOE) increased to
$10.9 million during the third quarter of 2010 compared to
$9.7 million during the same period in 2009. On a unit of
production basis, LOE costs decreased to $0.20 per Mcfe at
September 30, 2010 compared to $0.21 per Mcfe at
September 30, 2009 largely as a result of increased
production volumes during the quarter ended September 30,
2010.
During the three months ended September 30, 2010,
production taxes were $23.2 million compared to
$15.2 million during the same period in 2009, or $0.42 per
Mcfe compared to $0.33 per Mcfe. The increase in per unit taxes
is attributable to increased sales revenues as a result of
increased natural gas prices, excluding the effects of commodity
derivatives, during the quarter ended September 30, 2010 as
compared to the same period in 2009. During the three months
ended September 30, 2010, the Companys average price
for natural gas was $4.08 per Mcf, excluding realized gains and
losses on commodity derivatives, as compared to $3.09 per Mcf
for the same period in 2009. Production taxes are calculated
based on a percentage of revenue from production and were 9.6%
of revenues for the quarter ended September 30, 2010 and
9.8% of revenues for the same period in 2009.
Gathering fees increased to $12.6 million for the three
months ended September 30, 2010 compared to
$11.4 million during the same period in 2009 largely due to
increased production volumes. On a per unit basis, gathering
fees decreased to $0.23 per Mcfe for the three months ended
September 30, 2010 as compared to $0.25 per Mcfe during the
same period in 2009 as a result of increased production in
Pennsylvania, which is not subject to gathering fees.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production into relatively higher priced Northeastern markets
and to provide for reasonable basis differentials for its
natural gas, the Company incurred firm transportation charges
totaling $16.2 million for the quarter ended
September 30, 2010 as compared to $16.3 million for
the same period in 2009 in association with Rockies Express
Pipeline (REX) transportation charges. On a per unit
basis, transportation charges decreased to $0.29 per Mcfe (on
total company volumes) for the three months ended
September 30, 2010 as compared to $0.35 per Mcfe (on total
company volumes) for the same period in 2009 due to the increase
in production volumes during the quarter ended
September 30, 2010.
DD&A expenses increased to $59.7 million during the
three months ended September 30, 2010 from
$46.4 million for the same period in 2009, attributable
primarily to increased production volumes. On a unit of
production basis, DD&A increased to $1.08 per Mcfe for the
quarter ended September 30, 2010 from $1.01 per Mcfe for
the quarter ended September 30, 2009.
General and administrative expenses increased to
$6.0 million for the quarter ended September 30, 2010
compared to $5.1 million for the same period in 2009. The
increase in general and administrative expenses is primarily
attributable to increased headcount and related compensation. On
a per unit basis, general and administrative expenses were $0.11
per Mcfe for the quarters ended September 30, 2010 and 2009.
Interest expense increased to $11.4 million during the
quarter ended September 30, 2010 compared to
$9.7 million during the same period in 2009 as a result of
increased borrowings during the period ended September 30,
2010. At September 30, 2010, the Company had
$1.3 billion in borrowings outstanding. In
21
addition, the Company capitalized $6.5 million in interest
expense for the quarter ended September 30, 2010 related to
unevaluated oil and gas properties and on work in process
relating to gathering systems that are not currently in service
(See Note 3). There was no capitalized interest for the
same period in 2009.
During the quarter ended September 30, 2010, the Company
recognized $40.6 million of realized gain on commodity
derivatives as compared to $89.6 million of realized gain
on commodity derivatives during the quarter ended
September 30, 2009. The realized gain or loss on commodity
derivatives relates to actual amounts received or paid under
these derivative contracts.
During the quarter ended September 30, 2010, the Company
recognized $109.6 million in unrealized gain on commodity
derivatives as compared to $145.0 million in unrealized
loss on commodity derivatives during the quarter ended
September 30, 2009. The unrealized gain or loss on
commodity derivatives represents the change in the fair value of
these derivative instruments over the remaining term of the
contract.
The Company recognized income before income taxes of
$250.7 million for the quarter ended September 30,
2010 compared with a loss before income tax benefit of
$13.9 million for the same period in 2009. The increase in
earnings is primarily a result of increased revenues resulting
from increased production during the three months ended
September 30, 2010 as compared to the same period in 2009
along with the change in the gain or loss on commodity
derivatives during the quarter ended September 30, 2010 as
compared to the same period in 2009.
The income tax provision recognized for the quarter ended
September 30, 2010 was $88.1 million compared with an
income tax benefit of $5.6 million for the three months
ended September 30, 2009. The increase is largely a result
of increased revenues resulting from increased production as
well as the change in the gain or loss on commodity derivatives
during the quarter ended September 30, 2010 as compared to
the same period in 2009. The effective tax rate for the quarter
ended September 30, 2010 decreased as compared to the prior
period primarily due to certain reconciling items related to the
filing of the 2008 U.S. Income Tax return in the third
quarter of 2009.
For the three months ended September 30, 2010, the Company
recognized net income of $162.6 million or $1.05 per
diluted share as compared with a net loss of $8.3 million
or ($0.06) per diluted share for the same period in 2009. The
increase is primarily attributable to increased revenues
resulting from increased production during the three months
ended September 30, 2010 as compared to the same period in
2009 along with the change in the gain or loss on commodity
derivatives during the quarter ended September 30, 2010 as
compared to the same period in 2009.
NINE
MONTHS ENDED SEPTEMBER 30, 2010 VS. NINE MONTHS ENDED
SEPTEMBER 30, 2009
During the nine months ended September 30, 2010, production
increased 18% on a gas equivalent basis to 156.4 Bcfe from
132.5 Bcfe for the same period in 2009 attributable to the
Companys successful drilling activities during 2009 and in
the first nine months of 2010. Realized natural gas prices,
including realized gains and losses on commodity derivatives,
increased 2% to $5.00 per Mcf in the nine months ended 2010 as
compared to $4.89 per Mcf for the same period in 2009. During
the nine months ended September 30, 2010, the
Companys average price for natural gas was $4.49 per Mcf,
excluding realized gains and losses on commodity derivatives as
compared to $3.24 per Mcf for the same period in 2009. The
increase in average natural gas prices along with the increase
in production contributed to a 64% increase in revenues to
$741.9 million as compared to $453.5 million in 2009.
LOE increased to $32.7 million during the nine months of
2010 compared to $30.1 million during the same period in
2009. On a unit of production basis, LOE costs decreased to
$0.21 per Mcfe at September 30, 2010 compared to $0.23 per
Mcfe at September 30, 2009 largely as a result of increased
production volumes during the nine months ended
September 30, 2010.
During the nine months ended September 30, 2010, production
taxes were $74.1 million compared to $45.3 million
during the same period in 2009, or $0.47 per Mcfe compared to
$0.34 per Mcfe. The increase in per unit taxes is attributable
to increased sales revenues as a result of increased realized
gas prices during the nine months ended September 30, 2010
as compared to the same period in 2009. Production taxes are
22
calculated based on a percentage of revenue from production and
were 10.0% of revenues for the nine months ended
September 30, 2010 and 2009.
Gathering fees increased to $37.1 million for the nine
months ended September 30, 2010 compared to
$33.8 million during the same period in 2009 largely due to
increased production volumes. On a per unit basis, gathering
fees decreased to $0.24 per Mcfe for the nine months ended
September 30, 2010 as compared to $0.25 per Mcfe during the
same period in 2009 as a result of increased production in
Pennsylvania, which is not subject to gathering fees.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production into relatively higher priced Northeastern markets
and to provide for reasonable basis differentials for its
natural gas, the Company incurred firm transportation charges
totaling $48.6 million for the nine months ended
September 30, 2010 as compared to $42.8 million for
the same period in 2009 in association with REX transportation
charges. On a per unit basis, transportation charges decreased
to $0.31 per Mcfe (on total company volumes) for the nine months
ended September 30, 2010 as compared to $0.32 per Mcfe (on
total company volumes) for the same period in 2009 due to the
increase in production volumes during the period ended
September 30, 2010 and partially offset by increased
transportation rates as a result of further eastern expansion of
REX.
DD&A expenses increased to $167.8 million during the
nine months ended September 30, 2010 from
$152.0 million for the same period in 2009, attributable to
increased production volumes and partially offset by a lower
depletion rate due mainly to a lower depletable base as a result
of the ceiling test write-down during the first quarter of 2009.
On a unit of production basis, DD&A decreased to $1.07 per
Mcfe for the nine months ended September 30, 2010 from
$1.15 per Mcfe for the nine months ended September 30,
2009. The Company recorded a $1.0 billion non-cash
write-down of the carrying value of the Companys proved
oil and gas properties at March 31, 2009 as a result of
ceiling test limitations. The write-down reduced earnings in the
first quarter of 2009 and results in a lower DD&A rate in
future periods.
General and administrative expenses increased to
$18.5 million for the nine months ended September 30,
2010 compared to $15.4 million for the same period in 2009.
The increase in general and administrative expenses is primarily
attributable to increased headcount and related compensation. On
a per unit basis, general and administrative expenses remained
flat at $0.12 per Mcfe for the nine months ended
September 30, 2010 and 2009.
Interest expense increased to $34.5 million during the nine
months ended September 30, 2010 compared to
$26.9 million during the same period in 2009 as a result of
increased borrowings during the period ended September 30,
2010. At September 30, 2010, the Company had
$1.3 billion in borrowings outstanding. In addition, the
Company capitalized $13.9 million in interest expense for
the nine months ended September 30, 2010 related to
unevaluated oil and gas properties and on work in process
relating to gathering systems that are not currently in service
(See Note 3). There was no capitalized interest for the
same period in 2009.
During the nine months ended September 30, 2010, the
Company recognized $77.6 million of realized gain on
commodity derivatives as compared to $209.2 million of
realized gain on commodity derivatives during the nine months
ended September 30, 2009. The realized gain or loss on
commodity derivatives relates to actual amounts received or paid
under these derivative contracts.
During the nine months ended September 30, 2010, the
Company recognized $268.5 million in unrealized gain on
commodity derivatives as compared to $118.9 million in
unrealized loss on commodity derivatives during the nine months
ended September 30, 2009. The unrealized gain or loss on
commodity derivatives represents the change in the fair value of
these derivative instruments over the remaining term of the
contract.
During the nine months ended September 30, 2010, the
Company recognized litigation expenses of $9.9 million
related to the resolution of litigation matters.
Other expense for the nine months ended September 30, 2009
includes rig termination payments of $3.1 million that were
not incurred during the same period in 2010.
23
The Company recognized income before income taxes of
$665.0 million for the nine months ended September 30,
2010 compared with a loss before income tax benefit of
$842.5 million for the same period in 2009. The increase in
earnings is primarily a result of the non-cash write-down of oil
and gas properties associated with the ceiling test limitation
during the first quarter of 2009 and increased natural gas
prices and increased production during the nine months ended
September 30, 2010 as compared to the same period in 2009.
The income tax provision recognized for the nine months ended
September 30, 2010 was $238.5 million compared with an
income tax benefit of $296.0 million for the nine months
ended September 30, 2009. The increase is largely due to
increased income during the nine months ended September 30,
2010 compared with a loss before income tax benefit of
$842.5 million primarily as a result of the non-cash
write-down of oil and gas properties associated with the ceiling
test limitation during the first quarter of 2009. The effective
tax rate for the nine months ended September 30, 2010
increased as compared to the prior period primarily due to
elevated activity levels in the higher state tax rate
jurisdiction of Pennsylvania. A one-time
catch-up was
required, which caused the effective tax rate for the nine
months ended September 30, 2010 to increase to 35.9%.
For the nine months ended September 30, 2010, the Company
recognized net income of $426.5 million or $2.77 per
diluted share as compared with net loss of $546.4 million
or ($3.61) per diluted share for the same period in 2009. The
increase is primarily attributable to the non-cash write-down of
oil and gas properties associated with the ceiling test
limitation during the first quarter of 2009 and increased
natural gas prices and increased production during the nine
months ended September 30, 2010 as compared to the same
period in 2009.
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 nine month period ended September 30, 2010, the
Company relied on cash provided by operations along with
borrowings under the senior credit facility and the issuance of
the 2010A Senior Notes to finance its capital expenditures.
During this period, the Company participated in the drilling of
361 wells in Wyoming and Pennsylvania. For the nine month
period ended September 30, 2010, total capital expenditures
were $1.3 billion ($401.0 million to acquire
additional acreage in the Pennsylvania Marcellus Shale,
$831.4 million related to oil and gas exploration and
development expenditures and $61.3 million related to
gathering system expenditures).
At September 30, 2010, the Company reported a cash position
of $7.2 million compared to $13.0 million at
September 30, 2009. Working capital deficit at
September 30, 2010 was $105.5 million compared to
deficit of $118.4 million at September 30, 2009. At
September 30, 2010, we had $291.0 million in
outstanding borrowings and $209.0 million of available
borrowing capacity under the credit facility. In addition, the
Company had $1.0 billion outstanding under its Senior Notes
(See Note 4). Other long-term obligations of
$64.0 million at September 30, 2010 is comprised of
items payable in more than one year, primarily related to
production taxes and asset retirement obligations.
The Companys available cash, existing credit facility and
the cash generated from operations, are projected to be
sufficient to meet the Companys obligations and to fund
the budgeted capital investment program for 2010, which is
currently projected to be $1.1 billion, exclusive of
acquisitions. Of the $1.1 billion budget, the Company plans
to allocate approximately 60% to Wyoming and 40% to Pennsylvania.
24
In 2010, the Company closed the purchase of additional acreage
in the Pennsylvania Marcellus Shale for $401.0 million.
This transaction is incremental to the 2010 budgeted capital
investment program discussed above. In addition, the Company
traded and consolidated its land position in Pennsylvania during
the first quarter of 2010, which resulted in net proceeds of
$68.4 million.
The Companys land position in Pennsylvania continues to
expand. Including the acquisition of undeveloped acreage in the
Marcellus Shale during the first quarter of 2010, as well as
additional acreage acquired during the second quarter of 2010
for $60.1 million, partially offset by the consolidation of
the Companys land position for net proceeds of
$68.4 million during the first quarter of 2010, the
Companys acreage position in Pennsylvania is approximately
260,000 net acres.
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 the Companys 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 the Companys consolidated
leverage ratio (125.0 basis points per annum as of
September 30, 2010).
At September 30, 2010, the Company had $291.0 million
in outstanding borrowings and $209.0 million of available
borrowing capacity under the 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 three and one half times; and as long as
the Companys debt rating is below investment grade, the
maintenance of an annual ratio of the net present value of the
Companys oil and gas properties to total funded debt of at
least 1.75 to 1.00. At September 30, 2010, the Company was
in compliance with all of its debt covenants under the credit
facility.
Senior Notes: On January 28, 2010, Ultra
Resources, Inc., issued $500.0 million of Senior Notes
(the 2010A Senior Notes) pursuant to a Second
Supplement to the Master Note Purchase Agreement between the
Company and the purchasers of the Notes.
The Senior Notes rank pari passu with the Companys bank
credit facility. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation.
The Senior Notes are pre-payable in whole or in part at any time
and are subject to representations, warranties, covenants and
events of default customary for a senior note financing. At
September 30, 2010, the Company was in compliance with all
of its debt covenants under the Master Note Purchase Agreement
(See Note 4).
Operating Activities. During the nine months
ended September 30, 2010, net cash provided by operating
activities was $604.1 million, a 44% increase from
$420.8 million for the same period in 2009. The increase in
net cash provided by operating activities is largely
attributable to the increase in realized natural gas prices and
increased production during the nine months ended
September 30, 2010 as compared to the same period in 2009.
Investing Activities. During the nine months
ended September 30, 2010, net cash used in investing
activities was $1.1 billion as compared to
$586.9 million for the same period in 2009. The increase in
net cash used in investing activities is largely due to
increased capital investments associated with the Pennsylvania
Marcellus Shale acquisition in February 2010 and the
Companys drilling activities in 2010 as compared to
25
2009, partially offset by the proceeds from the sale of
undeveloped acreage during the nine months ended
September 30, 2010.
Financing Activities. During the nine months
ended September 30, 2010, net cash provided by financing
activities was $527.0 million as compared to
$165.0 million for the same period in 2009. The increase in
net cash provided by financing activities is largely due to
increased borrowings, primarily attributable to the 2010A Senior
Notes offering, during the nine months ended September 30,
2010 as compared to the same period in 2009.
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of September 30, 2010.
CAUTIONARY
STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding the Companys financial
position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of the
Companys management for future operations, covenant
compliance and those statements preceded by, followed by or that
otherwise include the words believe,
expects, anticipates,
intends, estimates,
projects, target, goal,
plans, objective, should, or
similar expressions or variations on such expressions are
forward-looking statements. The Company can give no assurances
that the assumptions upon which such forward-looking statements
are based will prove to be correct nor can the Company assure
adequate funding will be available to execute the Companys
planned future capital program.
Other risks and uncertainties include, but are not limited to,
fluctuations in the price the Company receives for oil and gas
production, reductions in the quantity of oil and gas sold due
to increased industry-wide demand
and/or
curtailments in production from specific properties due to
mechanical, marketing or other problems, operating and capital
expenditures that are either significantly higher or lower than
anticipated because the actual cost of identified projects
varied from original estimates
and/or from
the number of exploration and development opportunities being
greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates.
We are also subject to risks associated with the current
unprecedented volatility in the financial markets, including the
duration of the crisis and effectiveness of government
solutions. See the Companys annual report on
Form 10-K
for the year ended December 31, 2009 and its
Form 10-Q
for the quarters ended March 31, 2010 and June 30,
2010 for additional risks related to the Companys business.
|
|
ITEM 3
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
natural gas production. Historically, prices received for
natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were
26
converted at no cost to the Company and the conversion of these
contracts to derivative instruments was effective upon entering
into these transactions in March 2009, with upcoming settlements
for production months through December 2010. The natural gas
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
independent third parties.
From time to time, the Company may use fixed price forward gas
sales to manage its commodity price exposure. These fixed price
forward gas sales are considered normal sales in the ordinary
course of business and outside the scope of FASB ASC 815,
Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At September 30, 2010, 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. See Note 8 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
Volume -
|
|
Average
|
|
September 30,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
6,473
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
79,746
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
10,000
|
|
|
$
|
6.27
|
|
|
$
|
8,288
|
|
Swap
|
|
NW Rockies
|
|
Oct 10
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
2,524
|
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
25,740
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
165,000
|
|
|
$
|
5.71
|
|
|
$
|
67,141
|
|
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the nine months and quarters ended
September 30, 2010 and 2009 (refer to Note 2 for
details of unrealized gains or losses included in accumulated
other comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
40,583
|
|
|
$
|
89,620
|
|
|
$
|
77,568
|
|
|
$
|
209,180
|
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
|
109,603
|
|
|
|
(145,048
|
)
|
|
|
268,535
|
|
|
|
(118,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on commodity derivatives
|
|
$
|
150,186
|
|
|
$
|
(55,428
|
)
|
|
$
|
346,103
|
|
|
$
|
90,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain (loss) on commodity derivatives in the
Consolidated Statements of Operations. |
ITEM 4
CONTROLS AND PROCEDURES
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
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
27
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
September 30, 2010. There were no changes in our internal
control over financial reporting during the nine months ended
September 30, 2010 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 the Companys Annual Report on
Form 10-K
for the fiscal year ended December 31, 2009 and on the
Companys Quarterly Report on
Form 10-Q
for the quarters ended March 31, 2010 and June 30,
2010.
ITEM 2. UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS
UPON SENIOR SECURITIES
None.
ITEM 4. [REMOVED
AND RESERVED]
ITEM 5. OTHER
INFORMATION
None.
28
ITEM 6. EXHIBITS
(a) Exhibits
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
101
|
.DEF**
|
|
XBRL Taxonomy Extension Definition.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
29
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: November 4, 2010
|
|
|
|
By:
|
/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
|
Title:
|
Chief Financial Officer
|
Date: November 4, 2010
30
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.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
101
|
.DEF**
|
|
XBRL Taxonomy Extension Definition.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
31