e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
September 30,
2011
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or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number 001-33614
ULTRA PETROLEUM CORP.
(Exact name of registrant as
specified in its charter)
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Yukon Territory, Canada
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N/A
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. employer
identification number)
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400 North Sam Houston Parkway E.,
Suite 1200, Houston, Texas
(Address of principal
executive offices)
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77060
(Zip
code)
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(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):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(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 25, 2011 was
152,717,724.
Part I
Financial Information
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Item 1
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Financial
Statements
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ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF INCOME
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For the Three Months
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For the Nine Months
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Ended September 30,
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Ended September 30,
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2011
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2010
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2011
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2010
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(Amounts in thousands, except per share data)
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(Unaudited)
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Revenues:
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Natural gas sales
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$
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262,147
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$
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217,890
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$
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743,898
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$
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674,845
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Oil sales
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30,994
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22,484
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87,101
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67,041
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Total operating revenues
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293,141
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240,374
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830,999
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741,886
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Expenses:
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Lease operating expenses
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12,381
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10,850
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35,853
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32,708
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Production taxes
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25,676
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23,191
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73,796
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74,084
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Gathering fees
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14,445
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12,616
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41,363
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37,069
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Transportation charges
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16,061
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16,201
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48,492
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48,628
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Depletion, depreciation and amortization
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85,795
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59,674
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238,773
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167,795
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General and administrative
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6,185
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5,957
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19,298
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18,464
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Total operating expenses
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160,543
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128,489
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457,575
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378,748
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Operating income
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132,598
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111,885
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373,424
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363,138
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Other income (expense), net:
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Interest expense
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(15,902
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(11,382
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(46,082
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(34,538
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Gain on commodity derivatives
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114,166
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150,186
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177,407
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346,103
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Litigation expense
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(9,902
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)
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Other (expense) income, net
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(3
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12
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14
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185
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Total other income (expense), net
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98,261
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138,816
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131,339
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301,848
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Income before income tax provision
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230,859
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250,701
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504,763
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664,986
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Income tax provision
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81,713
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88,059
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183,392
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238,477
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Net income
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$
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149,146
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$
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162,642
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$
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321,371
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$
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426,509
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Net income per common share basic
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$
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0.98
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$
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1.07
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$
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2.10
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$
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2.80
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Net income per common share fully diluted
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$
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0.97
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$
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1.05
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$
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2.08
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$
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2.77
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Weighted average common shares outstanding basic
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152,817
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152,479
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152,772
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152,286
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Weighted average common shares outstanding fully
diluted
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154,280
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154,192
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154,418
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154,241
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See accompanying notes to consolidated financial statements.
3
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
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September 30,
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December 31,
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2011
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2010
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(Unaudited)
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(Amounts in thousands of U.S. dollars, except share
data)
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ASSETS
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Current Assets:
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Cash and cash equivalents
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$
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12,309
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$
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70,834
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Restricted cash
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109
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98
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Oil and gas revenue receivable
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90,774
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95,142
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Joint interest billing and other receivables
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75,258
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48,561
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Derivative assets
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146,510
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133,991
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Inventory
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1,548
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2,760
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Prepaid drilling costs and other current assets
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8,160
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9,663
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Total current assets
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334,668
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361,049
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Oil and gas properties, net, using the full cost method of
accounting:
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Proved
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3,411,536
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2,589,423
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Unproved properties not being amortized
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526,579
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486,247
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Property, plant and equipment
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180,997
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149,104
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Long-term derivative assets
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17,149
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2,066
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Deferred financing costs and other
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7,103
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7,726
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Total assets
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$
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4,478,032
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$
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3,595,615
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LIABILITIES AND SHAREHOLDERS EQUITY
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Current liabilities:
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Accounts payable and accrued liabilities
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$
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239,681
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$
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210,311
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Current portion of long-term debt
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278,000
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Production taxes payable
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61,585
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53,382
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Deferred tax liabilities
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44,617
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42,685
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Interest payable
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8,175
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26,878
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Derivative liabilities
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718
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Capital cost accrual
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156,610
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84,042
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Total current liabilities
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788,668
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418,016
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Long-term debt
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1,560,000
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1,560,000
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Deferred income tax liabilities
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588,903
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420,711
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Long-term derivative liabilities
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5,337
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Other long-term obligations
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76,992
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52,575
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Commitments and contingencies
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Shareholders equity:
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Common stock no par value; authorized
unlimited; issued and outstanding 152,717,724 and
152,567,813 at September 30, 2011 and December 31,
2010, respectively
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457,411
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426,779
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Treasury stock
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(7,694
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Retained earnings
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1,013,752
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712,197
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Total shareholders equity
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1,463,469
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1,138,976
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Total liabilities and shareholders equity
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$
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4,478,032
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$
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3,595,615
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See accompanying notes to consolidated financial statements.
4
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
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Nine Months Ended
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September 30,
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2011
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2010
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(Unaudited)
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(Amounts in thousands of U.S. dollars)
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Cash provided by (used in):
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Operating activities:
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Net income for the period
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$
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321,371
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$
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426,509
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Adjustments to reconcile net income to cash provided by
operating activities:
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Depletion and depreciation
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238,773
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167,795
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Deferred income taxes
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176,566
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230,936
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Unrealized (gain) on commodity derivatives
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(33,658
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)
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(268,535
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)
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Excess tax benefit from stock based compensation
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(6,441
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)
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(16,386
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)
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Stock compensation
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9,892
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9,122
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Other
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783
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473
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Net changes in operating assets and liabilities:
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Restricted cash
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(11
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(82
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Accounts receivable
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(22,329
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)
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(5,008
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Prepaid expenses and other
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(1,927
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)
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(3,236
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)
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Other non-current assets
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(135
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)
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2,905
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Accounts payable, production taxes, interest payable and accrued
liabilities
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18,016
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36,264
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Other long-term obligations
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14,432
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20,562
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Taxation payable/receivable, net
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4,460
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2,825
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Net cash provided by operating activities
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719,792
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604,144
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Investing Activities:
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Acquisition of oil and gas properties
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(400,993
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Oil and gas property expenditures
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(1,081,450
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)
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(831,423
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)
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Gathering system expenditures
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(35,179
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)
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(61,343
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Restricted cash
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28,257
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Change in capital cost accrual
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72,568
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59,928
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Proceeds from sale of oil and gas properties
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68,420
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Inventory
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1,212
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(233
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Purchase of capital assets
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(939
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)
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(769
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)
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Net cash used in investing activities
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(1,043,788
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)
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(1,138,156
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)
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Financing activities:
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Borrowings on long-term debt
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896,000
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986,000
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Payments on long-term debt
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(618,000
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)
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(955,000
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)
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Proceeds from issuance of Senior Notes
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500,000
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Deferred financing costs
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(2,265
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)
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Repurchased shares/net share settlements
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(28,625
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)
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(23,707
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)
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Excess tax benefit from stock based compensation
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6,441
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16,386
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Proceeds from exercise of options
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9,655
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|
|
|
5,562
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|
|
|
|
|
|
|
|
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Net cash provided by financing activities
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|
|
265,471
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|
|
|
526,976
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Decrease in cash during the period
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|
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(58,525
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)
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|
|
(7,036
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)
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Cash and cash equivalents, beginning of period
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|
|
70,834
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|
|
|
14,254
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|
|
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|
|
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Cash and cash equivalents, end of period
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$
|
12,309
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|
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$
|
7,218
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|
|
|
|
|
|
|
|
|
|
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, 2010, 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, 2010 was derived from the Companys
audited financial statements. The Companys management
believes that these financial statements include all adjustments
necessary for a fair presentation of the Companys
financial position and results of operations. All adjustments
are of a normal and recurring nature unless specifically noted.
The Company prepared these statements on a basis consistent with
the Companys annual audited statements and
Regulation S-X.
Regulation S-X
allows the Company to omit some of the footnote and policy
disclosures required by generally accepted accounting principles
and normally included in annual reports on
Form 10-K.
You should read these interim financial statements together with
the financial statements, summary of significant accounting
policies and notes to the Companys most recent annual
report on
Form 10-K.
Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries. The Company presents its financial
statements in accordance with U.S. GAAP. All inter-company
transactions and balances have been eliminated upon
consolidation.
(a) Cash and Cash Equivalents: The
Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
(b) Restricted Cash: Restricted cash
represents cash received by the Company from production sold
where the final division of ownership of the production is
unknown or in dispute.
(c) Property, Plant and
Equipment: Capital assets are recorded at cost
and depreciated using the declining-balance method based on 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: The
Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and
Exchange Commission (SEC) Release
No. 33-8995,
Modernization of Oil and Gas Reporting Requirements (SEC
Release
No. 33-8995)
and Financial Accounting Standards Board (FASB)
Accounting Standards Codification (ASC) Topic 932,
Extractive Activities Oil and Gas (FASB
ASC 932). Under this method of accounting, the costs
of unsuccessful, as well as successful, exploration and
development activities are capitalized as oil and gas
properties. This includes any internal costs that are directly
related to exploration and development activities but does not
include any costs related to production, general corporate
overhead or similar activities. The carrying amount of oil and
natural gas properties also includes estimated asset retirement
costs recorded based on the fair value of the asset retirement
obligation when incurred. Gain or loss on the sale or other
disposition of oil and natural gas properties is not recognized,
unless the gain or loss would significantly alter the
relationship between capitalized costs and proved reserves of
oil and natural gas attributable to a country.
6
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The sum of net capitalized costs and estimated future
development costs of oil and natural gas properties are
amortized using the
units-of-production
method based on the Companys proved reserves. Oil and
natural gas reserves and production are converted into
equivalent units based on relative energy content. Asset
retirement obligations are included in the base costs for
calculating depletion.
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10%, plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
results in a lower depletion, depreciation and amortization
(DD&A) rate in future periods. A write-down may
not be reversed in future periods even though higher oil and
natural gas prices may subsequently increase the ceiling.
(e) Inventories: Materials and supplies
inventories are carried at lower of cost or market. 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, 2011,
inventory of $1.5 million primarily included the cost of
pipe and production equipment that are expected to be utilized
during the 2011 and 2012 drilling programs.
(f) Derivative Instruments and Hedging
Activities: Currently, the Company largely relies
on commodity derivative contracts to manage its exposure to
commodity price risk. These 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 physical, fixed price forward natural
gas sales in order to mitigate its commodity price exposure on a
portion of its natural gas production. These fixed price forward
natural 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 6).
(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 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, the Company recognizes
the financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely
than not sustain the position following an audit.
(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
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
(Share amounts in 000s)
|
|
|
Net income
|
|
$
|
149,146
|
|
|
$
|
162,642
|
|
|
$
|
321,371
|
|
|
$
|
426,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic
|
|
|
152,817
|
|
|
|
152,479
|
|
|
|
152,772
|
|
|
|
152,286
|
|
Effect of dilutive instruments
|
|
|
1,463
|
|
|
|
1,713
|
|
|
|
1,646
|
|
|
|
1,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully
diluted
|
|
|
154,280
|
|
|
|
154,192
|
|
|
|
154,418
|
|
|
|
154,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic
|
|
$
|
0.98
|
|
|
$
|
1.07
|
|
|
$
|
2.10
|
|
|
$
|
2.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share fully diluted
|
|
$
|
0.97
|
|
|
$
|
1.05
|
|
|
$
|
2.08
|
|
|
$
|
2.77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of shares not included in dilutive earnings per share
that would have been anti-dilutive because the exercise price
was greater than the average market price of the common shares
|
|
|
1,168
|
|
|
|
989
|
|
|
|
968
|
|
|
|
989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 under
GAAP, and expands disclosures about fair value measurements.
This statement applies under other accounting topics that
require or permit fair value measurements. See Note 7 for
additional information.
(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 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 revenue 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
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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) Capital Cost Accrual: The Company
accrues for exploration and development costs in the period
incurred, while payment may occur in a subsequent period.
|
|
2.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
5,629,692
|
|
|
$
|
4,575,222
|
|
Less: Accumulated depletion, depreciation and amortization
|
|
|
(2,218,156
|
)
|
|
|
(1,985,799
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
3,411,536
|
|
|
|
2,589,423
|
|
|
|
|
|
|
|
|
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized(1)
|
|
|
526,579
|
|
|
|
486,247
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs oil and gas properties
|
|
$
|
3,938,115
|
|
|
$
|
3,075,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the nine months ended September 30, 2011 and 2010,
total interest on outstanding debt was $69.0 million and
$48.4 million, respectively, of which, $21.3 million
and $13.1 million, respectively, was capitalized on the
cost of unevaluated oil and natural gas properties and
$1.6 million and $0.8 million, respectively, on work
in process relating to gathering systems that are not currently
in service. |
|
|
3.
|
DEBT AND
OTHER LONG-TERM OBLIGATIONS:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
Short-term debt:
|
|
|
|
|
|
|
|
|
Bank indebtedness
|
|
$
|
278,000
|
|
|
$
|
|
|
Long-term obligations:
|
|
|
|
|
|
|
|
|
Senior Notes
|
|
|
1,560,000
|
|
|
|
1,560,000
|
|
Other long-term obligations
|
|
|
76,992
|
|
|
|
52,575
|
|
|
|
|
|
|
|
|
|
|
Total long-term obligations
|
|
$
|
1,636,992
|
|
|
$
|
1,612,575
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness: At September 30, 2011,
the Company (through its subsidiary, Ultra Resources) was a
party to a revolving credit facility with a syndicate of banks
led by JP Morgan Chase Bank, N.A. which was to mature in April
2012 (the 2007 Credit Agreement). On October 6,
2011, in anticipation of the upcoming maturity of the 2007
Credit Agreement, the Company, through Ultra Resources (the
Borrower), replaced the 2007 Credit Agreement in its
entirety with a senior unsecured revolving credit facility with
JP Morgan Chase Bank, N.A. as administrative agent, and the
lenders party thereto (the 2011 Credit Agreement)
and repaid all amounts outstanding under the 2007 Credit
Agreement with proceeds of loans drawn under the 2011 Credit
Agreement. (For a description of the 2011 Credit Agreement, see
Note 9).
9
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The 2007 Credit Agreement provided an initial loan commitment of
$500.0 million. Loans under the 2007 Credit Agreement were
unsecured and bore 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 Borrowers consolidated leverage ratio
(125 basis points per annum as of September 30, 2011).
At September 30, 2011, the Company had $278.0 million
in outstanding borrowings and $222.0 million of available
borrowing capacity under the 2007 Credit Agreement.
The 2007 Credit Agreement had restrictive covenants that
included the maintenance of a ratio of consolidated funded debt
to EBITDAX (earnings before interest, taxes, DD&A and other
non-cash charges) not to exceed three and one half times; and as
long as the Companys debt rating was 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,
2011, the Company was in compliance with all of its debt
covenants under the 2007 Credit Agreement.
Senior Notes: The Senior Notes rank pari passu
with the Companys 2007 Credit Agreement and the 2011
Credit Agreement. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation. The Senior
Notes are pre-payable in whole or in part at any time and are
subject to representations, warranties, covenants and events of
default customary for a senior note financing. At
September 30, 2011, the Company was in compliance with all
of its debt covenants under the Master Note Purchase Agreement
for Senior Notes.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable and asset retirement obligations.
|
|
4.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
Ended September 30,
|
|
Ended September 30,
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
Total cost of share-based payment plans
|
|
$
|
5,344
|
|
|
$
|
4,778
|
|
|
$
|
15,475
|
|
|
$
|
15,273
|
|
Amounts capitalized in fixed assets
|
|
$
|
1,898
|
|
|
$
|
1,793
|
|
|
$
|
5,583
|
|
|
$
|
6,151
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
3,446
|
|
|
$
|
2,985
|
|
|
$
|
9,892
|
|
|
$
|
9,122
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
1,237
|
|
|
$
|
1,060
|
|
|
$
|
3,551
|
|
|
$
|
3,238
|
|
10
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, 2011 and the year ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
|
Options
|
|
|
Exercise Price
|
|
|
|
(000s)
|
|
|
(US$)
|
|
|
Balance, December 31, 2009
|
|
|
3,504
|
|
|
$
|
1.49
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(68
|
)
|
|
$
|
51.60
|
|
|
|
to
|
|
|
$
|
76.01
|
|
Exercised
|
|
|
(1,206
|
)
|
|
$
|
1.49
|
|
|
|
to
|
|
|
$
|
45.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2010
|
|
|
2,230
|
|
|
$
|
3.91
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(20
|
)
|
|
$
|
51.60
|
|
|
|
to
|
|
|
$
|
75.18
|
|
Exercised
|
|
|
(661
|
)
|
|
$
|
3.91
|
|
|
|
to
|
|
|
$
|
33.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2011
|
|
|
1,549
|
|
|
$
|
16.97
|
|
|
|
to
|
|
|
$
|
98.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PERFORMANCE
SHARE PLANS:
Long Term Incentive Plans. The Company offers
a Long Term Incentive Plan (LTIP) in order to
further align the interests of key employees with shareholders
and to give key employees the opportunity to share in the
long-term performance of the Company when specific corporate
financial and operational goals are achieved. Each LTIP covers a
performance period of three years. In 2009, 2010 and 2011, the
Compensation Committee (the Committee) approved an
award consisting of performance-based restricted stock units to
be awarded to each participant.
For each LTIP award, the Committee establishes performance
measures at the beginning of each performance period. Under each
LTIP, the 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 as a
target value which corresponds to the number of
shares of the Companys common stock the participant is
eligible to receive if the target level for all performance
measures is met. In addition, each participant is assigned
threshold and maximum award levels in the event that actual
performance is below or above target levels. For LTIP awards in
each of 2009, 2010, and 2011 the Committee established the
following performance measures: return on equity, reserve
replacement ratio, and production growth.
For the nine months ended September 30, 2011, the Company
recognized $7.5 million in pre-tax compensation expense
related to the 2009, 2010 and 2011 LTIP awards of restricted
stock units as compared to $5.9 million during the nine
months ended September 30, 2010 related to the 2008, 2009
and 2010 LTIP awards of restricted stock units. The amounts
recognized during the nine months ended September 30, 2011
assumes that maximum performance objectives are attained. If the
Company ultimately attains these performance objectives, the
associated total compensation, estimated at September 30,
2011, for each of the three year performance periods is expected
to be approximately $23.8 million, $11.5 million, and
$11.2 million related to the 2009, 2010 and 2011 LTIP
awards of restricted stock units, respectively. The 2008 LTIP
award of restricted stock units was paid in shares of the
Companys stock to employees during the first quarter of
2011 and totaled $4.3 million (41,443 net shares).
During the quarter ended September 30, 2011, the Company
recorded an income tax provision of $81.7 million, or 35.4%
of income before income tax provision. This compares to an
income tax provision of $88.1 million, or 35.1% of income
before income tax provision for the quarter ended
September 30, 2010. The effective tax rate
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
increased over the comparable prior period primarily due to
elevated activity levels in the higher state tax jurisdiction of
Pennsylvania and offset in part due to certain reconciling items
related to the filing of the 2010 U.S. Income Tax return in
the third quarter of 2011.
During the nine months ended September 30, 2011, the
Company recorded an income tax provision of $183.4 million,
or 36.3% of income before income tax provision. This compares to
an income tax provision of $238.5 million, or 35.9% of
income before income tax provision for the nine months ended
September 30, 2010. The effective tax rate increased over
the comparable prior period primarily due to elevated activity
levels in the higher state tax jurisdiction of Pennsylvania as
the higher effective tax rate is now being applied to the
Companys prior temporary differences which increased the
overall effective tax rate.
|
|
6.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
natural gas production. Historically, prices received for
natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue. As a result of its
hedging activities, the Company may realize prices that are less
than or greater than the spot prices that it would have received
otherwise.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
The Companys hedging policy limits the amounts of
resources hedged to not more than 50% of its forecast production
without Board approval. The Board has approved hedging greater
than 50% of the Companys forecast 2011 production.
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.
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 income or expense 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 do not impact operating cash
flows on the cash flow statement. See Note 7 for the detail
of the fair value of the following derivatives.
Commodity Derivative Contracts: At
September 30, 2011, 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. The natural gas
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
independent third parties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
Remaining
|
|
|
|
|
|
Fair Value -
|
|
|
Reference
|
|
Contract
|
|
Volume -
|
|
Average
|
|
September 30,
|
Type
|
|
Price
|
|
Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Asset
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
170,000
|
|
|
$
|
5.08
|
|
|
$
|
21,611
|
|
Swap
|
|
NYMEX
|
|
October 2011
|
|
|
230,000
|
|
|
$
|
4.58
|
|
|
$
|
5,875
|
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
300,000
|
|
|
$
|
5.03
|
|
|
$
|
86,311
|
|
Swap
|
|
NYMEX
|
|
April October 2012
|
|
|
90,000
|
|
|
$
|
5.00
|
|
|
$
|
15,557
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
195,000
|
|
|
$
|
5.81
|
|
|
$
|
34,305
|
|
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the pre-tax realized and
unrealized gains the Company recognized related to its natural
gas derivative instruments in the Consolidated Statements of
Income for the three and nine months ended September 30,
2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
Natural Gas Commodity Derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
53,630
|
|
|
$
|
40,583
|
|
|
$
|
143,749
|
|
|
$
|
77,568
|
|
Unrealized gain on commodity derivatives(1)
|
|
|
60,536
|
|
|
|
109,603
|
|
|
|
33,658
|
|
|
|
268,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
114,166
|
|
|
$
|
150,186
|
|
|
$
|
177,407
|
|
|
$
|
346,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Income. |
|
|
7.
|
FAIR
VALUE MEASUREMENTS:
|
As required by FASB ASC 820, the Company defines fair value
as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date and establishes a three
level hierarchy for measuring fair value. Fair value
measurements are classified and disclosed in one of the
following categories:
Level 1: Quoted prices
(unadjusted) in active markets for identical assets and
liabilities that the Company has the ability to access at the
measurement date.
Level 2: Inputs other than quoted
prices included within Level 1 that are either directly or
indirectly observable for the asset or liability, including
quoted prices for similar assets or liabilities in active
markets, quoted prices for identical or similar assets or
liabilities in inactive markets, inputs other than quoted prices
that are observable for the asset or liability, and inputs that
are derived from observable market data by correlation or other
means. Instruments categorized in Level 2 include
non-exchange traded derivatives such as
over-the-counter
forwards and swaps.
Level 3: Unobservable inputs for
the asset or liability, including situations where there is
little, if any, market activity for the asset or liability.
The valuation assumptions utilized to measure the fair value of
the Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level the
Companys assets, including both current and non-current
portions, measured at fair value on a recurring basis, as of
September 30, 2011. The Company has no derivative
instruments which qualify for cash flow hedge accounting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
146,510
|
|
|
$
|
|
|
|
$
|
146,510
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
17,149
|
|
|
$
|
|
|
|
$
|
17,149
|
|
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.
13
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Fair
Value of Financial Instruments
The estimated fair value of financial instruments is the
estimated amount at which the instrument could be exchanged
currently between willing parties. The carrying amounts reported
in the consolidated balance sheet for cash and cash equivalents,
accounts receivable, accounts payable and current portion of
long-term debt approximate fair value due to the immediate or
short-term maturity of these financial instruments. The Company
uses available market data and valuation methodologies to
estimate the fair value of 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, 2011
|
|
|
December 31, 2010
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.45% Notes due 2015, issued 2008
|
|
$
|
100,000
|
|
|
$
|
111,002
|
|
|
$
|
100,000
|
|
|
$
|
108,572
|
|
7.31% Notes due 2016, issued 2009
|
|
|
62,000
|
|
|
|
74,248
|
|
|
|
62,000
|
|
|
|
72,153
|
|
4.98% Notes due 2017, issued 2010
|
|
|
116,000
|
|
|
|
127,118
|
|
|
|
116,000
|
|
|
|
119,385
|
|
5.92% Notes due 2018, issued 2008
|
|
|
200,000
|
|
|
|
227,987
|
|
|
|
200,000
|
|
|
|
212,660
|
|
7.77% Notes due 2019, issued 2009
|
|
|
173,000
|
|
|
|
216,361
|
|
|
|
173,000
|
|
|
|
203,051
|
|
5.50% Notes due 2020, issued 2010
|
|
|
207,000
|
|
|
|
225,461
|
|
|
|
207,000
|
|
|
|
206,233
|
|
4.51% Notes due 2020, issued 2010
|
|
|
315,000
|
|
|
|
316,205
|
|
|
|
315,000
|
|
|
|
284,207
|
|
5.60% Notes due 2022, issued 2010
|
|
|
87,000
|
|
|
|
92,497
|
|
|
|
87,000
|
|
|
|
84,818
|
|
4.66% Notes due 2022, issued 2010
|
|
|
35,000
|
|
|
|
34,340
|
|
|
|
35,000
|
|
|
|
30,989
|
|
5.85% Notes due 2025, issued 2010
|
|
|
90,000
|
|
|
|
96,942
|
|
|
|
90,000
|
|
|
|
87,211
|
|
4.91% Notes due 2025, issued 2010
|
|
|
175,000
|
|
|
|
171,555
|
|
|
|
175,000
|
|
|
|
152,064
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,560,000
|
|
|
$
|
1,693,716
|
|
|
$
|
1,560,000
|
|
|
$
|
1,561,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Company has evaluated the
period subsequent to September 30, 2011 for events that did
not exist at the balance sheet date but arose after that date
and determined that no subsequent events other than those
discussed below arose that should be disclosed in order to keep
the financial statements from being misleading.
On October 6, 2011, in anticipation of the upcoming
maturity of the Companys (through its subsidiary, Ultra
Resources) senior unsecured revolving credit agreement dated
April 30, 2007 with a syndicate of banks led by JP Morgan
Chase Bank, N.A., the Company, through Ultra Resources, replaced
the 2007 Credit Agreement in its entirety with a senior
unsecured revolving credit facility with JP Morgan Chase Bank,
N.A. as administrative agent, and the lenders party thereto and
repaid all amounts outstanding under the 2007 Credit Agreement
with proceeds of loans drawn under the 2011 Credit Agreement.
14
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The 2011 Credit Agreement reflects an increased borrowing
capacity as compared to the 2007 Credit Agreement with an
initial loan commitment of $1.0 billion (which may be
increased up to $1.25 billion at the request of the
Borrower and with the lenders consent), provides for the
issuance of letters of credit of up to $250.0 million in
aggregate, and matures in five years (which term may be extended
for up to two successive one-year periods at the Borrowers
request and with the lenders consent).
Loans under the 2011 Credit Agreement are unsecured and bear
interest, at the Borrowers option, based on (A) a
rate per annum equal to the prime rate or the weighted average
fed funds rate on overnight transactions during the preceding
business day plus 50 basis points, or (B) a base
Eurodollar rate, substantially equal to the LIBOR rate, in
either case plus a margin based on a grid of the Borrowers
consolidated leverage ratio (for Eurodollar borrowings,
175 basis points per annum as of October 6, 2011).
The 2011 Credit Agreement contains typical and customary
representations, warranties, covenants and events of default.
The 2011 Credit Agreement includes restrictive covenants
requiring the Borrower to maintain a consolidated leverage ratio
of no greater than three and one half times to one and, as long
as the Companys debt rating is below investment grade, the
maintenance of an annual ratio of the net present value of the
Companys oil and gas properties to total funded debt of no
less than one and one half times to one.
15
Item 2
Managements Discussion and Analysis of Financial
Condition and Results of Operations
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the Companys consolidated financial statements and
related notes. Except as otherwise indicated, all amounts are
expressed in U.S. dollars.
Overview
Ultra Petroleum Corp. is an independent exploration and
production company focused on developing its long-life natural
gas reserves in the Green River Basin of Wyoming the
Pinedale and Jonah Fields and is in the early
exploration and development stages in the Appalachian Basin of
Pennsylvania. The Company operates in one industry segment,
natural gas and oil exploration and development with one
geographical segment, the United States.
The Company currently conducts operations exclusively in the
United States. Substantially all of its oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented reflect only the 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.
The Company currently generates substantially all of its
revenue, earnings and cash flow from the production and sales of
natural gas and oil. An increasing portion of the Companys
revenues is associated with natural gas sales from wells located
in the Appalachian Basin in Pennsylvania.
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, 2011, the average price realization for the
Companys natural gas was $5.17 per Mcf, including realized
gains and losses on commodity derivatives. The Companys
average price realization for natural gas was $4.29 per Mcf,
excluding the realized gains and losses on commodity
derivatives. (See Note 6).
The Company has consistently delivered meaningful reserve and
production growth over the past twelve 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 14% production growth on a gas equivalent
basis during the quarter ended September 30, 2011 as
compared to the same quarter in 2010.
Critical
Accounting Policies
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. Generally Accepted Accounting Principles
(GAAP). In addition, application of GAAP requires
the use of estimates, judgments and assumptions that affect the
reported amounts of assets and liabilities as of the date of the
financial statements as well as the revenues and expenses
reported during the period. Changes in these estimates related
to judgments and assumptions will occur as a result of future
events, and, accordingly, actual results could differ from
amounts estimated. Set forth below is a discussion of the
critical accounting policies used in the preparation of the
Companys financial statements which the Company believes
involve the most complex or subjective decisions or assessments.
Derivative Instruments and Hedging
Activities. Currently, the Company largely relies
on derivative instruments (generally, financial swaps) to manage
its exposure to commodity price risk. Additionally, and from
time to time, the Company enters into fixed price forward
natural gas sales 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 Financial
Accounting Standards Board (FASB) Accounting
Standards Codification (ASC) Topic 815, Derivatives
and Hedging (FASB ASC 815).
16
The Company records the fair value of its commodity derivatives
as an asset or liability on the Consolidated Balance Sheets, and
records the changes in the fair value of its commodity
derivatives in the Consolidated Statements of Income as an
unrealized gain or loss on commodity derivatives.
Fair Value Measurements. The Company follows
FASB ASC Topic 820, Fair Value Measurements and Disclosures
(FASB ASC 820). Under FASB ASC 820, fair
value is defined as the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction
between market participants at measurement date and establishes
a three level hierarchy for measuring fair value. The valuation
assumptions utilized to measure the fair value of the
Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance
with the requirements of FASB ASC 820 and the Company aligned
the categories below with the Level 1, 2, and 3 fair value
measurements as defined by FASB ASC 820. The balance of net
unrealized gains and losses recognized for the Companys
energy-related derivative instruments at September 30, 2011
is summarized in the following table based on the inputs used to
determine fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1(a)
|
|
Level 2(b)
|
|
Level 3(c)
|
|
Total
|
|
|
(Amounts in 000s)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
146,510
|
|
|
$
|
|
|
|
$
|
146,510
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
17,149
|
|
|
$
|
|
|
|
$
|
17,149
|
|
|
|
|
(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 the passage of time impact net income as
accretion expense. The related capitalized costs, including
revisions thereto, are charged to expense through depletion,
depreciation and amortization (DD&A).
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, 2011 and 2010 was
$9.9 million and $9.1 million, respectively. At
September 30, 2011, there was no unrecognized compensation
cost related to non-vested share-based compensation arrangements
granted under stock option plans. See Note 4 for additional
information.
17
Full Cost Method of Accounting. The Company
uses the full cost method of accounting for oil and gas
exploration and development activities as defined by the
Securities and Exchange Commission (SEC) Release
No. 33-8995,
Modernization of Oil and Gas Reporting Requirements (SEC
Release
No. 33-8995)
and FASB ASC Topic 932, Extractive Activities Oil
and Gas (FASB ASC 932). Under the full cost
method of accounting, all costs associated with the exploration
for and development of oil and gas reserves are capitalized on a
country-by-country
basis. Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells and overhead charges directly related to acquisition,
exploration and development activities. Substantially all of the
oil and gas activities are conducted jointly with others and,
accordingly, the amounts reflect only the Companys
proportionate interest in such activities.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
results in a lower DD&A rate in future periods. A
write-down may not be reversed in future periods even though
higher oil and natural gas prices may subsequently increase the
ceiling. The Company did not have any write-downs related to the
full cost ceiling limitation during the nine months ended
September 30, 2011 or 2010.
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 2).
Conversion of barrels of oil to Mcfe of
gas. The Company converts Bbls of oil and other
liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or
liquids to six Mcfe. This conversion ratio, which is typically
used in the oil and gas industry, represents the approximate
energy equivalent of a barrel of oil or other liquids to an Mcf
of natural gas. The sales price of one Bbl of oil or liquids has
been much higher than the sales price of six Mcf of natural gas
over the last several years, so a six to one conversion ratio
does not represent the economic equivalency of six Mcf of
natural gas to a Bbl of oil or other liquids.
RESULTS
OF OPERATIONS
Quarter
Ended September 30, 2011 vs. Quarter Ended
September 30, 2010
During the quarter ended September 30, 2011, production
increased 14% on a gas equivalent basis to 63.4 Bcfe from
55.4 Bcfe for the same quarter in 2010. This increase in
production was attributable to the Companys successful
drilling activities during 2010 and in the first nine months of
2011. Realized natural gas prices, including realized gains and
losses on commodity derivatives, increased 7% to $5.17 per Mcf
in the third quarter of 2011 as compared to $4.84 per Mcf for
the same quarter of 2010. During the three months ended
September 30, 2011, the Companys average price for
natural gas was $4.29 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $4.08 per Mcf for
the same period in 2010. The increase in average natural gas
prices together with the increase in production contributed to a
22% increase in revenues to $293.1 million as compared to
$240.4 million in 2010.
18
Lease operating expense (LOE) increased to
$12.4 million during the third quarter of 2011 compared to
$10.9 million during the same period in 2010 primarily due
to increased production volumes. On a unit of production basis,
LOE costs remained flat at $0.20 per Mcfe at September 30,
2011 compared to September 30, 2010.
During the three months ended September 30, 2011,
production taxes were $25.7 million compared to
$23.2 million during the same period in 2010. Production
taxes are calculated based on a percentage of revenue from
production in Wyoming after certain deductions and were 8.8% of
revenues for the quarter ended September 30, 2011 and 9.6%
of revenues for the same period in 2010. During the three months
ended September 30, 2011, the Companys average price
for natural gas was $4.29 per Mcf, excluding realized gains and
losses on commodity derivatives, as compared to $4.08 per Mcf
for the same period in 2010. Production taxes were $0.40 per
Mcfe compared to $0.42 per Mcfe for the three months ended
September 30, 2011 and 2010, respectively. The decrease in
per unit costs is primarily attributable to increased production
in Pennsylvania, which is not subject to production taxes.
Gathering fees increased to $14.4 million for the three
months ended September 30, 2011 compared to
$12.6 million during the same period in 2010 largely due to
increased production volumes. On a per unit basis, gathering
fees remained flat at $0.23 per Mcfe for the three months ended
September 30, 2011 and 2010.
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 $16.1 million for the quarter ended
September 30, 2011 as compared to $16.2 million for
the same period in 2010 in association with Rockies Express
Pipeline (REX). On a per unit basis, transportation
charges decreased to $0.25 per Mcfe (on total company volumes)
for the three months ended September 30, 2011 as compared
to $0.29 per Mcfe (on total company volumes) for the same period
in 2010 due to the increase in production volumes during the
quarter ended September 30, 2011.
DD&A expenses increased to $85.8 million during the
three months ended September 30, 2011 from
$59.7 million for the same period in 2010, attributable
primarily to increased production volumes and a higher depletion
rate. On a unit of production basis, DD&A increased to
$1.35 per Mcfe for the quarter ended September 30, 2011
from $1.08 per Mcfe for the quarter ended September 30,
2010 largely as a result of increased well costs in Pennsylvania.
General and administrative expenses remained relatively flat at
$6.2 million for the quarter ended September 30, 2011
compared to $6.0 million for the same period in 2010. On a
per unit basis, general and administrative expenses decreased to
$0.10 per Mcfe for the quarter ended September 30, 2011 as
compared to $0.11 per Mcfe for the quarter ended
September 30, 2010 as a result of increased production
volumes during the quarter ended September 30, 2011.
Interest expense increased to $15.9 million during the
quarter ended September 30, 2011 compared to
$11.4 million during the same period in 2010 as a result of
increased borrowings outstanding during the period ended
September 30, 2011. At September 30, 2011, the Company
had $1.8 billion in borrowings outstanding. In addition,
the Company capitalized $7.4 million and $6.5 million
in interest expense for the quarters ended September 30,
2011 and 2010, respectively, related to unevaluated oil and gas
properties and work in process relating to gathering systems
that are not currently in service (See Note 2).
During the quarter ended September 30, 2011, the Company
recognized $53.6 million of realized gain on commodity
derivatives as compared to $40.6 million of realized gain
on commodity derivatives during the quarter ended
September 30, 2010. The realized gain on commodity
derivatives relates to actual amounts received under these
derivative contracts.
During the quarter ended September 30, 2011, the Company
recorded $60.5 million in unrealized gain on commodity
derivatives as compared to $109.6 million in unrealized
gain on commodity derivatives during the quarter ended
September 30, 2010. The unrealized gain on commodity
derivatives represents the change in the fair value of these
derivative instruments over the remaining term of the contract.
19
The Company recognized income before income taxes of
$230.9 million for the quarter ended September 30,
2011 compared with income before income taxes of
$250.7 million for the same period in 2010. The decrease in
earnings is primarily related to the change in the unrealized
gain on commodity derivatives during the quarter ended
September 30, 2011 as compared to the same period in 2010
and offset in part by the increase in revenues as a result of
the increase in production together with increased average
natural gas prices and realized gain on commodity derivatives.
The income tax provision recognized for the quarter ended
September 30, 2011 was $81.7 million compared with
$88.1 million for the three months ended September 30,
2010. The decrease is primarily related to the change in the
unrealized gain on commodity derivatives during the quarter
ended September 30, 2011 as compared to the same period in
2010 offset in part by the increase in revenues as a result of
the increase in production together with increased average
natural gas prices and realized gain on commodity derivatives.
The effective tax rate for the nine months ended
September 30, 2011 increased as compared to the prior
period primarily due to elevated activity levels in the higher
state tax rate jurisdiction of Pennsylvania and offset in part
due to certain reconciling items related to the filing of the
2010 U.S. Income Tax return in the third quarter of 2011.
For the three months ended September 30, 2011, the Company
recognized net income of $149.1 million or $0.97 per
diluted share as compared with net income of $162.6 million
or $1.05 per diluted share for the same period in 2010. The
decrease is primarily related to the change in the unrealized
gain on commodity derivatives during the quarter ended
September 30, 2011 as compared to the same period in 2010
offset in part by increased revenues as a result of the increase
in production together with increased average natural gas prices
and realized gain on commodity derivatives.
Nine
Months Ended September 30, 2011 vs. Nine Months Ended
September 30, 2010
During the nine months ended September 30, 2011, production
increased 14% on a gas equivalent basis to 178.4 Bcfe from
156.4 Bcfe for the same period in 2010 attributable to the
Companys successful drilling activities during 2010 and in
the first nine months of 2011. Realized natural gas prices,
including realized gains and losses on commodity derivatives,
increased 3% to $5.15 per Mcf in the nine months ended
September 30, 2011 as compared to $5.00 per Mcf for the
same period in 2010. During the nine months ended
September 30, 2011, the Companys average price for
natural gas was $4.32 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $4.49 per Mcf for
the same period in 2010. The increase in production offset in
part by the decrease in average natural gas prices, excluding
realized gains and losses on commodity derivatives, contributed
to a 12% increase in revenues to $831.0 million as compared
to $741.9 million in 2010.
LOE increased to $35.9 million during the nine months ended
September 30, 2011 compared to $32.7 million during
the same period in 2010 largely due to increased production. On
a unit of production basis, LOE costs decreased to $0.20 per
Mcfe at September 30, 2011 compared to $0.21 per Mcfe at
September 30, 2010 primarily due to increased production
volumes together with lower water handling costs as a result of
the initiation of the second phase of the liquids gathering
system of the Companys condensate and water gathering
facilities in Wyoming during 2011.
During the nine months ended September 30, 2011, production
taxes were $73.8 million compared to $74.1 million
during the same period in 2010. Production taxes are calculated
based on a percentage of revenue from production in Wyoming
after certain deductions and were 8.9% of revenues for the nine
months ended September 30, 2011 compared with 10.0% for the
same period in 2010. During the nine months ended
September 30, 2011, the Companys average price for
natural gas was $4.32 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $4.49 per Mcf for
the same period in 2010. Production taxes were $0.41 per Mcfe
compared to $0.47 per Mcfe for the nine months ended
September 30, 2011 and 2010, respectively. The decrease in
per unit taxes is primarily attributable to increased production
in Pennsylvania, which is not subject to production taxes, as
well as the decrease in average natural gas prices, excluding
the effects of commodity derivatives, during the nine months
ended September 30, 2011 as compared to the same period in
2010.
Gathering fees increased to $41.4 million for the nine
months ended September 30, 2011 compared to
$37.1 million during the same period in 2010 largely due to
increased production volumes. On a per unit basis, gathering
fees decreased to $0.23 per Mcfe for the nine months ended
September 30, 2011 as compared to $0.24 per
20
Mcfe during the same period in 2010 as a result of increased
production in Pennsylvania, which is subject to lower average
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 $48.5 million and $48.6 million for the nine
months ended September 30, 2011 and 2010, respectively, in
association with the REX pipeline. On a per unit basis,
transportation charges decreased to $0.27 per Mcfe (on total
company volumes) for the nine months ended September 30,
2011 as compared to $0.31 per Mcfe (on total company volumes)
for the same period in 2010 due to the increase in production
volumes during the period ended September 30, 2011.
DD&A expenses increased to $238.8 million during the
nine months ended September 30, 2011 from
$167.8 million for the same period in 2010, attributable
primarily to increased production volumes and a higher depletion
rate. On a unit of production basis, DD&A increased to
$1.34 per Mcfe for the nine months ended September 30, 2011
from $1.07 per Mcfe for the nine months ended September 30,
2010 largely as a result of increased well costs in Pennsylvania.
General and administrative expenses increased to
$19.3 million for the nine months ended September 30,
2011 compared to $18.5 million for the same period in 2010.
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 decreased
to $0.11 per Mcfe for the nine months ended September 30,
2011 compared with $0.12 per Mcfe for the same period in 2010 as
a result of increased production volumes during the period ended
September 30, 2011.
Interest expense increased to $46.1 million during the nine
months ended September 30, 2011 compared to
$34.5 million during the same period in 2010 as a result of
increased borrowings outstanding during the period ended
September 30, 2011. At September 30, 2011, the Company
had $1.8 billion in borrowings outstanding. In addition,
the Company capitalized $22.9 million and
$13.9 million in interest expense for the nine months ended
September 30, 2011 and 2010, respectively, related to
unevaluated oil and gas properties and work in process relating
to gathering systems that are not currently in service (See
Note 2).
During the nine months ended September 30, 2011, the
Company recognized $143.7 million of realized gain on
commodity derivatives as compared to $77.6 million of
realized gain on commodity derivatives during the nine months
ended September 30, 2010. The realized gain on commodity
derivatives relates to actual amounts received under these
derivative contracts.
During the nine months ended September 30, 2011, the
Company recorded $33.7 million in unrealized gain on
commodity derivatives as compared to $268.5 million in
unrealized gain on commodity derivatives during the nine months
ended September 30, 2010. The unrealized gain 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.
The Company recognized income before income taxes of
$504.8 million for the nine months ended September 30,
2011 compared with income before income taxes of
$665.0 million for the same period in 2010. The decrease in
earnings is primarily related to the change in the unrealized
gain on commodity derivatives during the nine months ended
September 30, 2011 as compared to the same period in 2010
offset in part by increased production and realized gain on
commodity derivatives during the nine months ended
September 30, 2011.
The income tax provision recognized for the nine months ended
September 30, 2011 was $183.4 million compared with
$238.5 million for the same period in 2010. The decrease is
largely a result of the change in the unrealized gain on
commodity derivatives during the nine months ended
September 30, 2011 as compared to the same period in 2010
offset in part by the increase in production and realized gain
on commodity derivatives during the nine months ended
September 30, 2011 as compared to the same period in 2010.
The effective tax rate for the
21
nine months ended September 30, 2011 increased as compared
to the prior period primarily due to elevated activity levels in
the higher state tax rate jurisdiction of Pennsylvania.
For the nine months ended September 30, 2011, the Company
recognized net income of $321.4 million or $2.08 per
diluted share as compared with net income of $426.5 million
or $2.77 per diluted share for the same period in 2010. The
decrease is primarily attributable to the change in the
unrealized gain on commodity derivatives offset in part by
increased production and realized gain on commodity derivatives
during the nine months ended September 30, 2011 as compared
to the same period in 2010.
LIQUIDITY
AND CAPITAL RESOURCES
During the nine month period ended September 30, 2011, the
Company relied on cash provided by operations along with
borrowings under the 2007 Credit Agreement to finance its
capital expenditures. During this period, the Company
participated in 355 gross (186.9 net) wells that were
drilled to total depth and cased in Wyoming and Pennsylvania.
For the nine month period ended September 30, 2011, total
capital expenditures were $1.1 billion ($1.08 billion
related to oil and gas exploration and development expenditures
and $35.2 million related to gathering system expenditures).
At September 30, 2011, the Company reported a cash position
of $12.3 million compared to $7.2 million at
September 30, 2010. Working capital deficit at
September 30, 2011 was $454.0 million compared to
working capital deficit of $105.5 million at
September 30, 2010. At September 30, 2011, the Company
had $278.0 million in outstanding borrowings and
$222.0 million of available borrowing capacity under the
2007 Credit Agreement (defined below). In addition, the Company
had $1.56 billion outstanding under its Senior Notes (See
Note 3). Other long-term obligations of $77.0 million
at September 30, 2011 was comprised of items payable in
more than one year, primarily related to production taxes and
asset retirement obligations.
The Companys available cash, credit facility (see
Note 9) and cash generated from operations, are
projected to be sufficient to meet the Companys
obligations and to fund the budgeted capital investment program
for 2011, which is currently projected to be $1.35 billion.
Bank indebtedness: At September 30, 2011,
the Company (through its subsidiary, Ultra Resources) was 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
(the 2007 Credit Agreement). On October 6,
2011, in anticipation of the upcoming maturity of the 2007
Credit Agreement, the Company, through Ultra Resources (the
Borrower), replaced the 2007 Credit Agreement in its
entirety with a senior unsecured revolving credit facility with
JP Morgan Chase Bank, N.A. as administrative agent, and the
lenders party thereto (the 2011 Credit Agreement)
and repaid all amounts outstanding under the 2007 Credit
Agreement with proceeds of loans drawn under the 2011 Credit
Agreement. (For a description of the 2011 Credit Agreement, see
Note 9 in the Notes to Consolidated Financial Statements
herein).
The 2007 Credit Agreement provided an initial loan commitment of
$500.0 million. Loans under the 2007 Credit Agreement were
unsecured and bore 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 Borrowers consolidated leverage ratio
(125 basis points per annum as of September 30, 2011).
At September 30, 2011, the Company had $278.0 million
in outstanding borrowings and $222.0 million of available
borrowing capacity under the 2007 Credit Agreement.
The 2007 Credit Agreement had restrictive covenants that
included the maintenance of a ratio of consolidated funded debt
to EBITDAX (earnings before interest, taxes, DD&A and other
non-cash charges) not to exceed three and one half times; and as
long as the Companys debt rating was 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,
2011, the Company was in compliance with all of its debt
covenants under the 2007 Credit Agreement.
22
Senior Notes: The Senior Notes rank pari passu
with the Companys 2007 Credit Agreement and the 2011
Credit Agreement. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation. The Senior
Notes are pre-payable in whole or in part at any time and are
subject to representations, warranties, covenants and events of
default customary for a senior note financing. At
September 30, 2011, the Company was in compliance with all
of its debt covenants under the Master Note Purchase Agreement
(See Note 3).
Operating Activities. During the nine months
ended September 30, 2011, net cash provided by operating
activities was $719.8 million, a 19% increase from
$604.1 million for the same period in 2010. The increase in
net cash provided by operating activities is largely
attributable to increased production and increased revenues
including realized gains on commodity derivatives during the
nine months ended September 30, 2011 as compared to the
same period in 2010.
Investing Activities. During the nine months
ended September 30, 2011, net cash used in investing
activities was $1.0 billion as compared to
$1.1 billion for the same period in 2010. The decrease in
net cash used in investing activities is largely associated with
the Pennsylvania Marcellus Shale acquisition in February 2010
and offset by increased capital investments associated with the
Companys drilling activities in 2011 as compared to 2010.
Financing Activities. During the nine months
ended September 30, 2011, net cash provided by financing
activities was $265.5 million as compared to
$527.0 million for the same period in 2010. The decrease in
net cash provided by financing activities is largely due to
decreased borrowings in 2011 as compared to 2010, primarily
attributable to the Senior Notes offering during the nine months
ended September 30, 2010.
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of September 30, 2011.
CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding the Companys financial
position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of the
Companys management for future operations, covenant
compliance and those statements preceded by, followed by or that
otherwise include the words believe,
expects, anticipates,
intends, estimates,
projects, target, goal,
plans, objective, should, or
similar expressions or variations on such expressions are
forward-looking statements. The Company can give no assurances
that the assumptions upon which such forward-looking statements
are based will prove to be correct nor can the Company assure
adequate funding will be available to execute the Companys
planned future capital program.
Other risks and uncertainties include, but are not limited to,
fluctuations in the price the Company receives for oil and gas
production, reductions in the quantity of oil and gas sold due
to increased industry-wide demand
and/or
curtailments in production from specific properties due to
mechanical, marketing or other problems, operating and capital
expenditures that are either significantly higher or lower than
anticipated because the actual cost of identified projects
varied from original estimates
and/or from
the number of exploration and development opportunities being
greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates.
See the Companys annual report on
Form 10-K
for the year ended December 31, 2010 for additional risks
related to the Companys business.
23
Item 3
Quantitative and Qualitative Disclosures About Market
Risk
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
natural gas production. Historically, prices received for
natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue. As a result of its
hedging activities, the Company may realize prices that are less
than or greater than the spot prices that it would have received
otherwise.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
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.
The Companys hedging policy limits the amounts of
resources hedged to not more than 50% of its forecast production
without Board approval. The Board has approved hedging greater
than 50% of the Companys forecast 2011 production.
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.
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 Consolidated Statements of Income. Unrealized gains or
losses on commodity derivatives represent the non-cash change in
the fair value of these derivative instruments and does not
impact operating cash flows on the cash flow statement. See
Note 7 for the detail of the fair value of the following
derivatives.
Commodity Derivative Contracts: At
September 30, 2011, 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. The natural gas
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
independent third parties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
|
|
|
|
|
|
Fair Value -
|
|
|
Reference
|
|
Remaining Contract
|
|
Volume -
|
|
Average
|
|
September 30,
|
Type
|
|
Price
|
|
Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
Asset
|
|
|
|
|
|
|
|
|
|
|
(Amounts in 000s)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
170,000
|
|
|
$
|
5.08
|
|
|
$
|
21,611
|
|
Swap
|
|
NYMEX
|
|
October 2011
|
|
|
230,000
|
|
|
$
|
4.58
|
|
|
$
|
5,875
|
|
Swap
|
|
NYMEX
|
|
Calendar 2012
|
|
|
300,000
|
|
|
$
|
5.03
|
|
|
$
|
86,311
|
|
Swap
|
|
NYMEX
|
|
April October 2012
|
|
|
90,000
|
|
|
$
|
5.00
|
|
|
$
|
15,557
|
|
Swap
|
|
Northeast
|
|
Calendar 2011
|
|
|
195,000
|
|
|
$
|
5.81
|
|
|
$
|
34,305
|
|
The following table summarizes the pre-tax realized and
unrealized gains the Company recognized related to its natural
gas derivative instruments in the Consolidated Statements of
Income for the three and nine months ended September 30,
2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
(Amounts in 000s)
|
|
|
Realized gain on commodity derivatives(1)
|
|
$
|
53,630
|
|
|
$
|
40,583
|
|
|
$
|
143,749
|
|
|
$
|
77,568
|
|
Unrealized gain on commodity derivatives(1)
|
|
|
60,536
|
|
|
|
109,603
|
|
|
|
33,658
|
|
|
|
268,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
114,166
|
|
|
$
|
150,186
|
|
|
$
|
177,407
|
|
|
$
|
346,103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Income. |
24
Item 4
Controls and Procedures
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
The Company has performed an evaluation under the supervision
and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures, as
defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act). The Companys disclosure controls and
procedures are the controls and other procedures that it has
designed to ensure that it records, processes, accumulates and
communicates information to the Companys management,
including its Chief Executive Officer and Chief Financial
Officer, to allow timely decisions regarding required
disclosures and submissions within the time periods specified in
the SECs rules and forms. All internal control systems, no
matter how well designed, have inherent limitations. Therefore,
even those determined to be effective can provide only a
reasonable assurance with respect to financial statement
preparation and presentation. Based on the evaluation, the
Companys management, including its Chief Executive Officer
and Chief Financial Officer, concluded that the Companys
disclosure controls and procedures were effective as of
September 30, 2011. There were no changes in the
Companys internal control over financial reporting during
the nine months ended September 30, 2011 that have
materially affected or are reasonably likely to affect, the
Companys 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, 2010.
Item 2. Changes
in Securities and Use of Proceeds
On May 17, 2006, the Company announced that its Board of
Directors authorized a share repurchase program for up to an
aggregate $1 billion of the Companys outstanding
common stock which has been and will be funded by cash on hand
and the Companys senior credit facility.
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Total Number
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Maximum
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of Shares
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Number (or
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Purchased as
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Approximate
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Part of Publicly
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Dollar Value)
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Total Number
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Announced
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that may yet
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of Shares
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Average Price
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Plans or
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be Purchased
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Purchased
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Paid per
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Programs
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Under the Plans
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Period
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(000s)
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Share
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(000s)
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or Programs
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July 2011
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$
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402 million
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August 2011
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221
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$
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36.24
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221
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$
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394 million
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September 2011
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$
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394 million
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25
Item 3. Defaults
Upon Senior Securities
None.
Item 4. [Removed
and Reserved]
Item 5. Other
Information
On November 2, 2011, Robert E. Rigney, a director of
the Company, submitted his resignation to the Board of
Directors. Mr. Rigney also resigned from the Companys
Audit Committee and Compensation Committee.
Mr. Rigneys departure is not related to any
disagreement with the Company or with the Companys
operations, policies or practices.
Item 6. Exhibits
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3
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.1
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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.)
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3
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.2
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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.)
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3
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.3
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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.)
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4
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.1
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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.)
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10
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.1
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Credit Agreement dated as of October 6, 2011 among Ultra
Resources, Inc. and JPMorgan Chase Bank, N.A. as Administrative
Agent, and the Lenders party thereto (incorporated
by reference to Exhibit 10.1 of the Companys Report on
Form 8K filed on October 11, 2011).
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31
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.1*
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Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
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31
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.2*
|
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Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
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32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
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32
|
.2*
|
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Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
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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. |
26
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.
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By:
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/s/ Michael
D. Watford
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Name: Michael D. Watford
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Title:
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Chairman, President and
|
Chief Executive Officer
Date: November 4, 2011
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|
|
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By:
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/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
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Title:
|
Senior Vice President and
|
Chief Financial Officer
Date: November 4, 2011
EXHIBIT INDEX
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
10
|
.1
|
|
Credit Agreement dated as of October 6, 2011 among Ultra
Resources, Inc. and JPMorgan Chase Bank, N.A. as Administrative
Agent, and the Lenders party thereto (incorporated
by reference to Exhibit 10.1 of the Companys Report
on Form 8K filed on October 11, 2011).
|
|
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. |
27