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 June 30,
2009
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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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363 North Sam Houston Parkway,
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 July 31, 2009 was
151,440,114.
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 OPERATIONS
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For the Three Months
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For the Six Months
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Ended June 30,
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Ended June 30,
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2009
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2008
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2009
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2008
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(Unaudited)
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(Amounts in thousands of U.S. dollars, except per share
data)
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Revenues:
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Natural gas sales
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$
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115,079
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$
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277,446
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$
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273,908
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$
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526,568
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Oil sales
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15,262
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30,794
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24,386
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52,809
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Total operating revenues
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130,341
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308,240
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298,294
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579,377
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Expenses:
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Lease operating expenses
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10,144
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8,562
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20,387
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19,299
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Production taxes
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12,738
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35,776
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30,089
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66,711
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Gathering fees
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11,573
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8,766
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22,364
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18,764
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Transportation charges
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13,185
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12,013
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26,540
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21,671
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Depletion and depreciation
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44,974
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42,780
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105,635
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85,030
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Write-down of proved oil and gas properties
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1,037,000
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General and administrative
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5,650
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4,449
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10,224
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8,794
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Total operating expenses
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98,264
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112,346
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1,252,239
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220,269
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Operating income (loss)
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32,077
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195,894
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(953,945
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)
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359,108
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Other income (expense), net:
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Interest expense
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(9,897
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(4,543
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(17,195
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)
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(9,814
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(Loss) gain on commodity derivatives
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(60,698
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)
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(11,596
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)
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145,730
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(39,269
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)
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Other (expense) income, net
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(505
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609
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(3,117
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692
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Total other (expense) income, net
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(71,100
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(15,530
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125,418
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(48,391
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(Loss) income before income tax (benefit) provision
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(39,023
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180,364
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(828,527
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310,717
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Income tax (benefit) provision
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(13,497
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63,489
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(290,413
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110,510
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Net (loss) income
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$
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(25,526
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$
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116,875
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$
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(538,114
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$
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200,207
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Net (loss) income per common share basic
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$
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(0.17
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$
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0.76
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$
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(3.56
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$
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1.31
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Net (loss) income per common share fully diluted
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$
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(0.17
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$
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0.74
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$
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(3.56
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$
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1.27
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Weighted average common shares outstanding basic
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151,331
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153,061
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151,285
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152,781
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Weighted average common shares outstanding fully
diluted
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151,331
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157,818
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151,285
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157,905
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See accompanying notes to consolidated financial statements.
3
ULTRA
PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
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June 30,
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December 31,
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2009
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2008
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(Unaudited)
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(Amounts in thousands of
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U.S. dollars)
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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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9,299
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$
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14,157
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Restricted cash
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1,682
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2,727
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Accounts receivable
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117,235
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126,710
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Derivative assets
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125,652
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39,939
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Inventory
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6,575
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8,522
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Prepaid drilling costs and other current assets
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2,778
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6,163
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Total current assets
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263,221
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198,218
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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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1,594,200
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2,294,982
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Unproved properties not being amortized
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55,544
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Property, plant and equipment
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5,972
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5,770
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Long-term derivative assets
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2,441
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Deferred financing costs and other
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7,656
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3,648
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Total assets
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$
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1,873,490
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$
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2,558,162
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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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106,374
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$
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163,902
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Production taxes payable
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73,069
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61,416
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Derivative liabilities
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3,665
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1,712
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Capital cost accrual
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60,759
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120,543
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Total current liabilities
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243,867
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347,573
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Long-term debt
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764,000
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570,000
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Deferred income tax liability
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206,358
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503,597
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Long-term derivative liabilities
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72,592
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Other long-term obligations
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29,415
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46,206
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Shareholders equity:
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Common stock no par value; authorized
unlimited; issued and outstanding 151,440,114 and
151,232,545, respectively
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356,535
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346,832
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Treasury stock
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(31,075
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(45,740
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Retained earnings
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224,373
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774,117
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Accumulated other comprehensive income
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7,425
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15,577
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Total shareholders equity
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557,258
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1,090,786
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Total liabilities and shareholders equity
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$
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1,873,490
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$
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2,558,162
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See accompanying notes to consolidated financial statements.
4
ULTRA
PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
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Six Months Ended
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June 30,
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2009
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2008
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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 (loss) income for the period
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$
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(538,114
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)
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$
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200,207
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Adjustments to reconcile net income to net cash provided by
operating activities:
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Income from discontinued operations, net of tax provision of $225
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(415
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)
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Depletion and depreciation
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105,635
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85,030
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Write-down of proved oil and gas properties
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1,037,000
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Deferred income taxes
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(290,436
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)
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110,704
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Unrealized (gain) loss on commodity derivatives
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(26,169
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)
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25,150
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Excess tax benefit from stock based compensation
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(2,394
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)
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(62,627
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)
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Stock compensation
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4,819
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2,755
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Other
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720
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189
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Net changes in non-cash working capital:
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Restricted cash
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1,045
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(34
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)
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Accounts receivable
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9,475
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(41,560
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)
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Prepaid expenses and other
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3,876
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(1,702
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)
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Other non-current assets
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(2,868
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)
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Accounts payable and accrued liabilities
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(45,519
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)
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76,058
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Other long-term obligations
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(16,670
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)
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20,424
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Current taxes payable
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(10,839
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)
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Net cash provided by operating activities
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240,400
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403,340
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Investing activities:
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Oil and gas property expenditures
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(382,366
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)
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(409,089
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)
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Post-closing adjustments on sale of subsidiary
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640
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Change in capital cost accrual
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(59,784
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)
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29,639
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Inventory
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1,947
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6,600
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Other
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(704
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)
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Purchase of capital assets
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(667
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)
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(461
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)
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Net cash used in investing activities
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(441,574
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)
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(372,671
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)
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Financing activities:
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Borrowings on long-term debt
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676,000
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332,000
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Payments on long-term debt
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(482,000
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)
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(322,000
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)
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Deferred financing costs
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(1,283
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)
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(1,580
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)
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Repurchased shares
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|
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(68,635
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)
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Excess tax benefit from stock based compensation
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2,394
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62,627
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Proceeds from exercise of options
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1,205
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16,631
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Net cash provided by financing activities
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196,316
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19,043
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(Decrease)/increase in cash during the period
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|
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(4,858
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)
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|
|
49,712
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Cash and cash equivalents, beginning of period
|
|
|
14,157
|
|
|
|
10,632
|
|
|
|
|
|
|
|
|
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|
Cash and cash equivalents, end of period
|
|
$
|
9,299
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|
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$
|
60,344
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
5
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All dollar amounts in this Quarterly Report on
Form 10-Q
are expressed in thousands of U.S. dollars (except per
share data) unless otherwise noted)
DESCRIPTION
OF THE BUSINESS:
Ultra Petroleum Corp. (the Company) is an
independent oil and gas company engaged in the acquisition,
exploration, development, and production of oil and gas
properties. The Company is incorporated under the laws of the
Yukon Territory, Canada. The Companys principal business
activities are conducted in the Green River Basin of Southwest
Wyoming.
|
|
1.
|
SIGNIFICANT
ACCOUNTING POLICIES:
|
The accompanying financial statements, other than the balance
sheet data as of December 31, 2008, are unaudited and were
prepared from the Companys records. Balance sheet data as
of December 31, 2008 was derived from the Companys
audited financial statements, but does not include all
disclosures required by U.S. Generally Accepted Accounting
Principles (GAAP). The Companys management
believes that these financial statements include all adjustments
necessary for a fair presentation of the Companys
financial position and results of operations. All adjustments
are of a normal and recurring nature unless specifically noted.
The Company prepared these statements on a basis consistent with
the Companys annual audited statements and
Regulation S-X.
Regulation S-X
allows the Company to omit some of the footnote and policy
disclosures required by generally accepted accounting principles
and normally included in annual reports on
Form 10-K.
You should read these interim financial statements together with
the financial statements, summary of significant accounting
policies and notes to the Companys most recent annual
report on
Form 10-K.
(a) Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries UP Energy Corporation and Ultra Resources,
Inc. The Company presents its financial statements in accordance
with GAAP. All inter-company transactions and balances have been
eliminated upon consolidation.
(b) Cash and cash equivalents: We
consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents.
(c) Restricted cash: Restricted cash
represents cash received by the Company from production sold
where the final division of ownership of the production is
unknown or in dispute. Wyoming law requires that these funds be
held in a federally insured bank in Wyoming.
(d) Capital assets other than oil and gas
properties: Capital assets are recorded at cost
and depreciated using the declining-balance method based on a
seven-year useful life.
(e) Oil and natural gas properties: The
Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and
Exchange Commission (SEC). Under this method of
accounting, the costs of unsuccessful, as well as successful,
exploration and development activities are capitalized as oil
and gas properties. This includes any internal costs that are
directly related to exploration and development activities but
does not include any costs related to production, general
corporate overhead or similar activities. The carrying amount of
oil and natural gas properties also includes estimated asset
retirement costs recorded based on the fair value of the asset
retirement obligation when incurred. Gain or loss on the sale or
other disposition of oil and natural gas properties is not
recognized, unless the gain or loss would significantly alter
the relationship between capitalized costs and proved reserves
of oil and natural gas attributable to a country.
The sum of net capitalized costs and estimated future
development costs of oil and natural gas properties are
amortized using the
units-of-production
method based on the proved reserves as determined by
independent
6
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
petroleum engineers. Oil and natural gas reserves and production
are converted into equivalent units based on relative energy
content. Asset retirement obligations are included in the base
costs for calculating depletion.
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing prices in effect on the last day of the
quarter. SEC
regulation S-X
Rule 4-10 states
that if prices in effect at the end of a quarter are the result
of a temporary decline and prices improve prior to the issuance
of the financial statements, the increased price may be applied
in the computation of the ceiling test. The ceiling limits such
pooled costs to the aggregate of the present value of future net
revenues attributable to proved crude oil and natural gas
reserves discounted at 10% plus the lower of cost or market
value of unproved properties less any associated tax effects. If
such capitalized costs exceed the ceiling, the Company will
record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down will reduce earnings in
the period of occurrence and result in lower DD&A expense
in future periods. A write-down may not be reversed in future
periods even though higher oil and natural gas prices may
subsequently increase the ceiling. The effect of implementing
SFAS No. 143 had no effect on the ceiling test
calculation as the future cash outflows associated with settling
asset retirement obligations are excluded from this calculation.
During the first quarter of 2009, the Company recorded a
$1.0 billion ($673.0 million net of tax) non-cash
write-down of the carrying value of the Companys proved
oil and gas properties as of March 31, 2009, as a result of
the ceiling test limitations, which is reflected as write-down
of oil and gas properties in the accompanying consolidated
statements of operations. The ceiling test was calculated based
on March 31, 2009 wellhead prices of $2.47 per Mcf for
natural gas and $33.91 per barrel for condensate.
(f) Inventories: Materials and supplies
inventories are carried at cost. Inventory costs include
expenditures and other charges directly and indirectly incurred
in bringing the inventory to its existing condition and
location. The Company uses the weighted average method of
recording its inventory. Selling expenses and general and
administrative expenses are reported as period costs and
excluded from inventory cost. At June 30, 2009, drilling
and completion supplies inventory of $6.6 million primarily
includes the cost of pipe and production equipment that will be
utilized during the 2009 drilling program.
(g) Derivative Instruments and Hedging
Activities: The Company relies on derivative
instruments to manage its exposure to commodity price risk. The
Company enters into fixed price to index price swap agreements
in order to mitigate its commodity price exposure on a portion
of its natural gas production. The natural gas reference prices
of these commodity derivative contracts are typically referenced
to natural gas index prices as published by independent third
parties. The Company also utilizes 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
SFAS No. 133. The Company does not offset the value of
its derivative arrangements with the same counterparty. (See
Note 6).
In March 2008, the FASB issued SFAS No. 161,
Disclosures about Derivative Instruments and Hedging
Activities (SFAS No. 161). This
statement is intended to improve financial reporting about
derivative instruments and hedging activities by requiring
enhanced disclosures to increase transparency about the location
and amounts of derivative instruments in an entitys
financial statements; how derivative instruments and related
hedged items are accounted for under SFAS No. 133; and
how derivative instruments and related
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
hedged items affect financial position, financial performance,
and cash flows. The Company adopted SFAS No. 161
effective January 1, 2009. The adoption of SFAS 161
did not have a material impact on the Companys results of
operations and financial condition.
(h) Income taxes: Income taxes are
accounted for under the asset and liability method. Deferred tax
assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities
and their respective tax basis and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in
the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. Valuation
allowances are recorded related to deferred tax assets based on
the more likely than not criteria of
SFAS No. 109.
The Company follows FASB Interpretation No. 48
(FIN 48) which requires that we recognize the
financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely
than not sustain the position following an audit.
(i) Earnings per share: Basic earnings
per share is computed by dividing net earnings attributable to
common stockholders by the weighted average number of common
shares outstanding during each period. Diluted earnings per
share is computed by adjusting the average number of common
shares outstanding for the dilutive effect, if any, of common
stock equivalents. The Company uses the treasury stock method to
determine the dilutive effect.
The following table provides a reconciliation of the components
of basic and diluted net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009(1)
|
|
|
2008
|
|
|
2009(2)
|
|
|
2008
|
|
|
Net (loss) income
|
|
$
|
(25,526
|
)
|
|
$
|
116,875
|
|
|
$
|
(538,114
|
)
|
|
$
|
200,207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
|
|
|
151,331
|
|
|
|
153,061
|
|
|
|
151,285
|
|
|
|
152,781
|
|
Effect of dilutive instruments
|
|
|
|
|
|
|
4,757
|
|
|
|
|
|
|
|
5,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
|
|
151,331
|
|
|
|
157,818
|
|
|
|
151,285
|
|
|
|
157,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic (Loss) Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
(0.17
|
)
|
|
$
|
0.76
|
|
|
$
|
(3.56
|
)
|
|
$
|
1.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted (Loss) Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share fully diluted
|
|
$
|
(0.17
|
)
|
|
$
|
0.74
|
|
|
$
|
(3.56
|
)
|
|
$
|
1.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Due to the net loss for the three months ended June 30,
2009, options for 2.2 million shares and 0.7 million
shares of restricted stock were anti-dilutive and excluded from
the computation of loss per share. |
|
(2) |
|
Due to the net loss for the six months ended June 30, 2009,
options for 2.2 million shares and 0.5 million shares
of restricted stock were anti-dilutive and excluded from the
computation of loss per share. |
(j) 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.
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(k) Accounting for share-based
compensation: The Company applies Statement of
Financial Accounting Standards No. 123 (revised 2004),
Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair values.
(l) Fair Value Accounting. In September
2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair
Value Measurements (SFAS No. 157).
This Statement defines fair value, establishes a framework for
measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurements. This statement applies under other accounting
pronouncements that require or permit fair value measurements.
Accordingly, this statement did not require any new fair value
measurements. The changes to current practice resulting from the
application of this statement relate to the definition of fair
value, the methods used to measure fair value, and the expanded
disclosures about fair value measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair value on a recurring basis, primarily our commodity
derivatives, with no material impact on consolidated results of
operations, financial position or liquidity. For those
non-financial assets and liabilities measured or disclosed at
fair value on a non-recurring basis, primarily our asset
retirement obligation,
SFAS No. 157-2
was effective January 1, 2009. Implementation of this
portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity. See Note 7 for additional information.
(m) Asset Retirement Obligation. The
initial estimated retirement obligation of properties is
recognized as a liability with an associated increase in oil and
gas properties for the asset retirement cost. Accretion expense
is recognized over the estimated productive life of the related
assets. If the fair value of the estimated asset retirement
obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions
in estimated liabilities can result from revisions of estimated
inflation rates, changes in service and equipment costs and
changes in the estimated timing of settling asset retirement
obligations.
(n) Revenue Recognition. Natural gas
revenues are recorded based on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Companys net interest. The Company initially
records its entitled share of revenues based on estimated
production volumes. Subsequently, these estimated volumes are
adjusted to reflect actual volumes that are supported by third
party pipeline statements or cash receipts. Since there is a
ready market for natural gas, the Company sells the majority of
its products immediately after production at various locations
at which time title and risk of loss pass to the buyer. Gas
imbalances occur when the Company sells more or less than its
entitled ownership percentage of total gas production. Any
amount received in excess of the Companys share is treated
as a liability. If the Company receives less than its entitled
share, the underproduction is recorded as a receivable.
(o) Other Comprehensive Income: Other
comprehensive income is a term used to define revenues,
expenses, gains and losses that under generally accepted
accounting principles impact Shareholders Equity,
excluding transactions with shareholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Six Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Net (loss) income
|
|
$
|
(25,526
|
)
|
|
$
|
116,875
|
|
|
$
|
(538,114
|
)
|
|
$
|
200,207
|
|
Loss on derivative instruments*
|
|
|
(7,145
|
)
|
|
|
(7,638
|
)
|
|
|
(12,561
|
)
|
|
|
(37,556
|
)
|
Tax benefit on loss on derivative instruments*
|
|
|
2,508
|
|
|
|
2,681
|
|
|
|
4,409
|
|
|
|
13,182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive (loss) income
|
|
$
|
(30,163
|
)
|
|
$
|
111,918
|
|
|
$
|
(546,266
|
)
|
|
$
|
175,833
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
* |
|
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet (See
Note 6). The net gain or loss in accumulated other
comprehensive income at November 3, 2008 will remain on the
balance sheet and the respective months gains or losses
will continue to be reclassified from accumulated other
comprehensive income to earnings as the counterparty settlements
affect earnings (January through December 2009). It is still
considered probable that the original forecasted transactions
will occur; therefore, the net gain or loss in accumulated other
comprehensive income shall not be immediately reclassified into
earnings. As a result of the de-designation on November 3,
2008, the company no longer has any derivative instruments which
qualify for cash flow hedge accounting. |
(p) Reclassifications: Certain amounts in
the financial statements of prior periods have been reclassified
to conform to the current period financial statement
presentation.
(q) Impact of recently issued accounting
pronouncements: On July 1, 2009, the FASB
approved the final version of the Codification, which is
effective for reporting periods after September 15, 2009.
The codification will become the single source of authoritative
U.S. GAAP. Going forward, U.S. GAAP will no longer be
issued in the form of an accounting standard, but
rather as an update to the applicable topic or
subtopic within the Codification. As such,
accounting guidance will be classified as either
authoritative or non-authoritative based on
its inclusion or exclusion from the Codification.
In April 2009, the FASB issued FSP
No. FAS 115-2
and
FAS 124-2,
Recognition and Presentation of
Other-Than-Temporary
Impairments (FSP
FAS 115-2
and
FAS 124-2),
which amends the existing
other-than-temporary
impairment guidance for debt securities to make the guidance
more operational and to improve the presentation and disclosure
of
other-than-temporary
impairments on debt and equity securities in the financial
statements.
Other-than-temporary
impairment relates to investments in debt and equity securities
for which changes in fair value are not regularly recognized in
earnings (such as securities classified as
held-to-maturity
or
available-for-sale).
This pronouncement is effective for interim and annual reporting
periods ending after June 15, 2009. Accordingly, the
Company has adopted this pronouncement for the quarter ended
June 30, 2009; however, since the Company has no such
investments in debt or equity securities, there was no impact on
the Companys financial position or results of operations
as a result of the adoption.
On December 31, 2008, the SEC issued Release
No. 33-8995,
Modernization of Oil and Gas Reporting, amending oil
and gas reporting requirements under
Rule 4-10
of
Regulation S-X
and Industry Guide 2 in
Regulation S-K
revising oil and gas reserves estimation and disclosure
requirements. The new rules include changes to pricing used to
estimate reserves, the ability to include non- traditional
resources in reserves, the use of new technology for determining
reserves and permitting disclosure of probable and possible
reserves. The primary objectives of the revisions are to
increase the transparency and information value of reserve
disclosures and improve comparability among oil and gas
companies. The rule is effective for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009. The
Company anticipates that the implementation of the new rule will
provide a more meaningful and comprehensive understanding of the
nature and associated risks of the Companys underlying oil
and gas reserves. The Company is continuing to evaluate the
impact of this release.
10
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
2.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
3,249,934
|
|
|
$
|
2,809,082
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(1,655,734
|
)
|
|
|
(514,100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,594,200
|
|
|
|
2,294,982
|
|
Unproven Properties*:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized
|
|
|
|
|
|
|
55,544
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,594,200
|
|
|
$
|
2,350,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
The Company holds interests in unproven properties in which
leasehold costs and seismic costs related to these interests of
$55.5 million were excluded from the amortization base at
December 31, 2008. Exclusion from amortization is permitted
in order to avoid distortion in the amortization per unit that
could result if the cost of unevaluated properties with no
proved reserves attributed to them was included in the
amortization base. Effective January 1, 2009, the Company
has determined that these costs are not significant enough to
warrant exclusion from the amortization base and has begun
amortizing the costs on a unit of production basis. |
During the first quarter of 2009, the Company recorded a
$1.0 billion ($673.0 million net of tax) non-cash
write-down of the carrying value of the Companys proved
oil and gas properties as of March 31, 2009, as a result of
the ceiling test limitations, which is reflected as write-down
of oil and gas properties in the accompanying consolidated
statements of operations. The ceiling test was calculated based
on March 31, 2009 wellhead prices of $2.47 per Mcf for
natural gas and $33.91 per barrel for condensate.
|
|
3.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Bank indebtedness
|
|
$
|
229,000
|
|
|
$
|
270,000
|
|
Senior notes
|
|
|
535,000
|
|
|
|
300,000
|
|
Other long-term obligations
|
|
|
29,415
|
|
|
|
46,206
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
793,415
|
|
|
$
|
616,206
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (100.0 basis points
per annum as of June 30, 2009).
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At June 30, 2009, we had $229.0 million in outstanding
borrowings and $271.0 million of available borrowing
capacity under our credit facility.
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At June 30, 2009, we were in compliance with all
of our debt covenants under our credit facility.
Senior Notes, due 2016 and 2019: On
March 5, 2009, our wholly-owned subsidiary, Ultra
Resources, Inc., issued $235.0 million Senior Notes
(the 2009 Senior Notes) pursuant to a Master Note
Purchase Agreement dated March 6, 2008 as supplemented by a
First Supplement thereto dated March 5, 2009 between the
Company and the purchasers of the 2009 Senior Notes. The 2009
Senior Notes rank pari passu with the Companys bank credit
facility. Payment of the 2009 Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation. Of the 2009
Senior Notes, $173.0 million are 7.77% senior notes
due March 1, 2019 and $62.0 million are
7.31% senior notes due March 1, 2016.
Proceeds from the sale of the 2009 Senior Notes were used to
repay bank debt, but did not reduce the borrowings available to
us under the revolving credit facility.
The 2009 Senior Notes are pre-payable in whole or in part at any
time. The 2009 Senior Notes are subject to representations,
warranties, covenants and events of default customary for a
senior note financing. If payment default occurs, any note
holder may accelerate its notes; if a non-payment default
occurs, holders of 51% of the outstanding principal amount of
the 2009 Senior Notes may accelerate all the 2009 Senior Notes.
At June 30, 2009, we were in compliance with all of our
debt covenants under the 2009 Senior Notes.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes
(the 2008 Senior Notes) pursuant to a Master Note
Purchase Agreement between the Company and the purchasers of the
Notes. The 2008 Senior Notes rank pari passu with the
Companys bank credit facility. Payment of the 2008 Senior
Notes is guaranteed by Ultra Petroleum Corp. and UP Energy
Corporation. Of the 2008 Senior Notes, $200.0 million are
5.92% senior notes due March 1, 2018 and
$100.0 million are 5.45% senior notes due
March 1, 2015.
Proceeds from the sale of the 2008 Senior Notes were used to
repay bank debt, but did not reduce the borrowings available to
us under the revolving credit facility. The 2008 Senior Notes
are pre-payable in whole or in part at any time. The 2008 Senior
Notes are subject to representations, warranties, covenants and
events of default customary for a senior note financing. If
payment default occurs, any note holder may accelerate its
notes; if a non-payment default occurs, holders of 51% of the
outstanding principal amount of the 2008 Senior Notes may
accelerate all the 2008 Senior Notes. At June 30, 2009, we
were in compliance with all of our debt covenants under the 2008
Senior Notes.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable and our asset retirement obligations.
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
4.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information under SFAS 123R
The following table summarizes share-based compensation expense
for the three and six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months
|
|
|
|
Three Months Ended June 30,
|
|
|
Ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Total cost of share-based payment plans
|
|
$
|
4,690
|
|
|
$
|
3,121
|
|
|
$
|
8,432
|
|
|
$
|
4,866
|
|
Amounts capitalized in fixed assets
|
|
$
|
1,996
|
|
|
$
|
1,220
|
|
|
$
|
3,613
|
|
|
$
|
2,111
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
2,694
|
|
|
$
|
1,901
|
|
|
$
|
4,819
|
|
|
$
|
2,755
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
945
|
|
|
$
|
667
|
|
|
$
|
1,690
|
|
|
$
|
967
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing. The Companys
employee stock options have various restrictions including
vesting provisions and restrictions on transfers and hedging,
among others, and are often exercised prior to their contractual
maturity. Expected volatilities used in the fair value estimates
are based on historical volatility of the Companys stock.
The Company uses historical data to estimate share option
exercises, expected term and employee departure behavior used in
the Black-Scholes pricing model. Groups of employees (executives
and non-executives) that have similar historical behavior are
considered separately for purposes of determining the expected
term used to estimate fair value. The assumptions utilized
result from differing pre- and post-vesting behaviors among
executive and non-executive groups. The risk-free rate for
periods within the contractual term of the share option is based
on the U.S. Treasury yield curve in effect at the time of
grant. There were no stock options granted during the six months
ended June 30, 2009.
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the six months ended June 30, 2009 and the year ended
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise Price
|
|
|
|
Options
|
|
|
(US$)
|
|
|
Balance, December 31, 2007
|
|
|
7,589
|
|
|
$
|
0.25 to $67.73
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
299
|
|
|
$
|
51.14 to $98.87
|
|
Forfeited
|
|
|
(80
|
)
|
|
$
|
51.60 to $85.05
|
|
Exercised
|
|
|
(3,595
|
)
|
|
$
|
0.25 to $67.73
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
4,213
|
|
|
$
|
0.25 to $98.87
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(43
|
)
|
|
$
|
51.60 to $78.55
|
|
Exercised
|
|
|
(163
|
)
|
|
$
|
2.04 to $33.57
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2009
|
|
|
4,007
|
|
|
$
|
0.25 to $98.87
|
|
|
|
|
|
|
|
|
|
|
13
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
PERFORMANCE
SHARE PLANS:
Long Term Incentive Plans. Each year since
2005, the Company has adopted a Long Term Incentive Plan
(LTIP) in order to further align the interests of
key employees with shareholders and to give key employees the
opportunity to share in the long-term performance of the Company
when specific corporate financial and operational goals are
achieved. Each LTIP covers a performance period of three years.
For 2007 and 2008, each LTIP had two components: an LTIP
Stock Option Award and an LTIP Common Stock
Award. In 2009, the Compensation Committee (the
Committee) approved an award consisting only of
performance-based restricted stock units to be awarded to each
participant.
Under each LTIP, the 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 (LTI Value). The LTIP Common Stock Award in
2007 and 2008 and the 2009 LTIP award of restricted stock units
are performance-based and are measured over a three year
performance period. For each LTIP award, the Committee
establishes performance measures at the beginning of each
performance period, and each participant is assigned threshold
and maximum award levels in the event that actual performance is
below or above target levels. For the 2007, 2008 and 2009 LTIP
awards, the Committee established the following performance
measures: return on equity, reserve replacement ratio, and
production growth.
For the six months ended June 30, 2009, the Company
recognized $2.4 million in pre-tax compensation expense
related to the 2007 LTIP Common Stock Award, 2008 LTIP Common
Stock Award and 2009 LTIP award of restricted stock units. For
the six months ended June 30, 2008, the Company recognized
$1.0 million in pre-tax compensation expense related to the
2006, 2007, and 2008 LTIP Common Stock Awards. The amounts
recognized during the six months ended June 30, 2009
assumes that maximum performance objectives are attained. If the
Company ultimately attains these performance objectives, the
associated total compensation, estimated at June 30, 2009,
for each of the three year performance periods is expected to be
approximately $3.9 million, $3.7 million, and
$9.6 million related to the 2007 LTIP Common Stock Award,
2008 LTIP Common Stock Award and 2009 LTIP award of restricted
stock units, respectively. Additional awards of restricted stock
units were granted to eligible employees during 2009 with
estimated total compensation of $9.5 million over the three
year performance period assuming that maximum performance
objectives are attained. The 2006 LTIP Common Stock Award was
paid in shares of the Companys stock to employees during
the first quarter of 2009 and totaled $2.7 million.
Best in Class Program. In May 2008, the
Company established the 2008 Best in Class Program for all
permanent, full-time employees. Under the 2008 Best in
Class Program, participants are eligible to receive a
number of shares of the Companys common stock based on the
performance of the Company. As with the LTIP, the 2008 Best in
Class Program is measured over a three year performance
period. The 2008 Best in Class Program recognizes and
financially rewards the collective efforts of all of the
Companys employees in achieving sustained industry leading
performance and the enhancement of shareholder value. Under the
2008 Best in Class Program, on January 1, 2008 or the
employment date if subsequent to January 1, 2008, eligible
employees received a contingent award of stock units equal to
$60,000 worth of the Companys common stock based on the
average high and low share price on the first day of the
performance period. Employees joining the Company after
January 1, 2008 participate on a pro-rata basis based on
their length of employment during the performance period.
The number of contingent units that will vest and become payable
is based on the Companys performance relative to the
industry during a three year performance period beginning
January 1, 2008, and ending December 31, 2010, and are
set at threshold (50%), target (100%), and maximum (150%)
levels. For each vested unit, the participant will receive one
share of common stock. The participant must be employed on the
date the awards are distributed in order to receive the award.
14
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
For the six months ended June 30, 2009, the Company
recognized $0.4 million in pre-tax compensation expense
related to the 2008 Best in Class Program. For the six
months ended June 30, 2008 the Company recognized
$0.3 million in pre-tax compensation expense related to the
2008 Best in Class Program. The amount recognized for the
six months ended June 30, 2009 and 2008 assumes that target
performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total
compensation related to the 2008 Best in Class Program is
estimated at $3.9 million at June 30, 2009.
The following table summarizes the components of income tax
(benefit) provision for the three and six months ended
June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Six Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
$
|
|
|
Rate
|
|
|
$
|
|
|
Rate
|
|
|
$
|
|
|
Rate
|
|
|
$
|
|
|
Rate
|
|
|
Current State tax payments
|
|
$
|
|
|
|
|
0.0
|
%
|
|
$
|
6
|
|
|
|
0.0
|
%
|
|
$
|
23
|
|
|
|
0.0
|
%
|
|
$
|
16
|
|
|
|
0.0
|
%
|
Current Federal tax credit
|
|
|
|
|
|
|
0.0
|
%
|
|
|
|
|
|
|
0.0
|
%
|
|
|
|
|
|
|
0.0
|
%
|
|
|
(209
|
)
|
|
|
(0.1
|
)%
|
Deferred tax (benefit) expense
|
|
|
( 13,497
|
)
|
|
|
(34.6
|
)%
|
|
|
63,483
|
|
|
|
35.3
|
%
|
|
|
(290,436
|
)
|
|
|
(35.1
|
)%
|
|
|
110,703
|
|
|
|
35.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) provision
|
|
$
|
( 13,497
|
)
|
|
|
(34.6
|
)%
|
|
$
|
63,489
|
|
|
|
35.3
|
%
|
|
$
|
(290,413
|
)
|
|
|
(35.1
|
)%
|
|
$
|
110,510
|
|
|
|
35.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
The Companys major market risk exposure is in the pricing
applicable to its natural gas and oil production. Realized
pricing is currently driven primarily by the prevailing price
for the Companys Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable. Pricing volatility is expected
to continue. Realized natural gas prices are derived from the
financial statements which include the effects of realized gains
and losses on commodity derivatives.
The Company relies on 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 Company
enters into fixed price to index price swap agreements in order
to mitigate its commodity price exposure on a portion of its
natural gas production. The natural gas reference prices of
these commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties such as Inside FERC Gas Market Report. The
Company also utilizes 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 SFAS No. 133.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
Unrealized gains or losses on commodity derivatives represents
the non-cash change in the fair value of these derivative
instruments and does not impact operating cash flows on the
Consolidated Statements of Cash Flows.
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement
15
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
rather than on the balance sheet. The net gain or loss in
accumulated other comprehensive income at November 3, 2008
will remain on the balance sheet and the respective months
gains or losses will continue to be reclassified from
accumulated other comprehensive income to earnings as the
counterparty settlements affect earnings (January through
December 2009). It is still considered probable that the
original forecasted transactions will occur; therefore, the net
gain or loss in accumulated other comprehensive income shall not
be immediately reclassified into earnings. As a result of the
de-designation on November 3, 2008, the company no longer
has any derivative instruments which qualify for cash flow hedge
accounting.
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provides operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010.
At June 30, 2009, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price. See Note 7 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
Volume-
|
|
|
Average
|
|
|
June 30,
|
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
|
Price/MMBTU
|
|
|
2009
|
|
|
Swap
|
|
Mid Continent
|
|
July 2009 October 2009
|
|
|
130,000
|
|
|
$
|
4.99
|
|
|
$
|
26,519
|
|
Swap
|
|
NW Rockies
|
|
July 2009 October 2009
|
|
|
130,000
|
|
|
$
|
5.85
|
|
|
$
|
48,166
|
|
Swap
|
|
NW Rockies
|
|
November 2009
|
|
|
50,000
|
|
|
$
|
3.53
|
|
|
$
|
(220
|
)
|
Swap
|
|
NW Rockies
|
|
July 2009 December 2009
|
|
|
100,000
|
|
|
$
|
5.65
|
|
|
$
|
43,272
|
|
Swap
|
|
NW Rockies
|
|
April 2010 October 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
1,499
|
|
Swap
|
|
NW Rockies
|
|
January 2010 December 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
(2,432
|
)
|
Swap
|
|
NW Rockies
|
|
January 2010 December 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
(60,436
|
)
|
Swap
|
|
Northeast
|
|
January 2010 December 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
(4,532
|
)
|
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the three and six months ended
June 30, 2009 and 2008 (refer to Note 1(o) for details
of unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Six Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain (loss) on derivatives(1)
|
|
$
|
99,205
|
|
|
$
|
(14,119
|
)
|
|
$
|
119,561
|
|
|
$
|
(14,119
|
)
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
$
|
(159,903
|
)
|
|
$
|
2,523
|
|
|
$
|
26,169
|
|
|
$
|
(25,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on commodity derivatives
|
|
$
|
(60,698
|
)
|
|
$
|
(11,596
|
)
|
|
$
|
145,730
|
|
|
$
|
(39,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain (loss) on commodity derivatives in the
Consolidated Statements of Operations. |
|
|
7.
|
FAIR
VALUE MEASUREMENTS:
|
On September 15, 2006, the FASB issued
SFAS No. 157, Fair Value Measurement. We
adopted SFAS No. 157 effective January 1, 2008.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the
16
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
measurement date and establishes a three level hierarchy for
measuring fair value. The statement requires fair value
measurements be classified and disclosed in one of the following
categories:
|
|
|
|
Level 1:
|
Quoted prices (unadjusted) in active markets for identical
assets and liabilities that we have the ability to access at the
measurement date.
|
|
|
Level 2:
|
Inputs other than quoted prices included within Level 1
that are either directly or indirectly observable for the asset
or liability, including quoted prices for similar assets or
liabilities in active markets, quoted prices for identical or
similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or
liability, and inputs that are derived from observable market
data by correlation or other means. Instruments categorized in
Level 2 include non-exchange traded derivatives such as
over-the-counter
forwards and swaps.
|
|
|
Level 3:
|
Unobservable inputs for the asset or liability, including
situations where there is little, if any, market activity for
the asset or liability.
|
The valuation assumptions utilized to measure the fair value of
the Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level our assets
and liabilities, including both current and non-current
portions, measured at fair value on a recurring basis, as of
June 30, 2009. The company has no derivative instruments
which qualify for cash flow hedge accounting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
125,652
|
|
|
$
|
|
|
|
$
|
125,652
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
2,441
|
|
|
$
|
|
|
|
$
|
2,441
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
3,665
|
|
|
$
|
|
|
|
$
|
3,665
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
72,592
|
|
|
$
|
|
|
|
$
|
72,592
|
|
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
For those non-financial assets and liabilities measured or
disclosed at fair value on a non-recurring basis, primarily
asset retirement obligations,
SFAS No. 157-2
was effective January 1, 2009. Implementation of this
portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity.
Fair
Market Value of Financial Instruments
The estimated fair value of financial instruments is the amount
at which the instrument could be exchanged currently between
willing parties. The carrying amounts reported in the
consolidated balance sheet for cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value
due to the immediate or short-term maturity of these financial
instruments. We use available market data and valuation
methodologies to estimate the fair value of debt. This
disclosure is presented in accordance with SFAS 107,
Disclosures about Fair Value of Financial
Instruments and does not impact our financial position,
results of operations or cash flows.
17
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In April 2009, the FASB issued FSP
FAS 107-1
and Accounting Principles Board (APB) Opinion
No. 28-1
(collectively, FSP
FAS 107-1),
Interim Disclosures about Fair Value of Financial
Instruments. FSP
FAS 107-1
amends SFAS No. 107, Disclosures about Fair
Value of Financial Instruments, to require an entity to
provide disclosures about fair value of financial instruments in
interim financial information. The FSP
FAS 107-1
also amends APB Opinion No. 28, Interim Financial
Reporting, to require those disclosures about the fair
value of financial instruments in summarized financial
information at interim reporting periods. Under FSP
FAS 107-1,
the Company is required to include disclosures about the fair
value of its financial instruments whenever it issues financial
information for interim reporting periods. In addition, the
Company is required to disclose in the body or in the
accompanying notes of its summarized financial information for
interim reporting periods and in its financial statements for
annual reporting periods, the fair value of all financial
instruments for which it is practicable to estimate that value,
whether recognized or not recognized in the statement of
financial position. FSP
FAS 107-1
is effective for periods ending after June 15, 2009 and its
adoption had no impact on the Companys results of
operations and financial condition but requires additional
disclosures about the fair value of financial instruments in the
financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
December 31, 2008
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Long-Term Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.45% Notes due 2015
|
|
$
|
100,000
|
|
|
$
|
99,899
|
|
|
$
|
100,000
|
|
|
$
|
93,836
|
|
5.92% Notes due 2018
|
|
|
200,000
|
|
|
|
197,765
|
|
|
|
200,000
|
|
|
|
180,729
|
|
7.31% Notes due 2016
|
|
|
62,000
|
|
|
|
67,690
|
|
|
|
|
|
|
|
|
|
7.77% Notes due 2019
|
|
|
173,000
|
|
|
|
190,540
|
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
|
229,000
|
|
|
|
229,000
|
|
|
|
270,000
|
|
|
|
270,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
$
|
764,000
|
|
|
$
|
784,894
|
|
|
$
|
570,000
|
|
|
$
|
544,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
In May 2009, the FASB issued SFAS No. 165, Subsequent
Events (SFAS No. 165), setting forth
principles and requirements to be applied to the accounting for
and disclosure of subsequent events. The statement 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.
SFAS No. 165 is effective for interim or annual
reporting periods ending after June 15, 2009, and shall be
applied prospectively. Accordingly, the Company has adopted this
pronouncement for the quarter ended June 30, 2009. The
Company has evaluated the period subsequent to June 30,
2009 and through August 4, 2009 (the date the financial
statements were available to be issued) for events that did not
exist at the balance sheet date but arose after that date and
determined that no subsequent events arose that should be
disclosed in order to keep the financial statements from being
misleading.
18
|
|
ITEM 2
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the consolidated financial statements and related notes of
the Company. Except as otherwise indicated, all amounts are
expressed in U.S. dollars. We operate in one industry
segment, natural gas and oil exploration and development with
one geographical segment, the United States.
The Company currently generates substantially all of its
revenue, earnings and cash flow from the production and sales of
natural gas and oil from its property in southwest Wyoming. The
price of natural gas in the southwest Wyoming region is a
critical factor to the Companys business. The price of gas
in southwest Wyoming historically has been volatile. The average
realizations for the period
2003-2009
have ranged from $2.33 to $8.81 per Mcf. This volatility could
be detrimental to the Companys financial performance. The
Company seeks to limit the impact of this volatility on its
results by entering into fixed price forward physical delivery
contracts and swap agreements for gas in southwest Wyoming.
During the quarter ended June 30, 2009, the average price
realization for the Companys natural gas was $5.04 per
Mcf, including realized gain or loss on commodity derivatives.
The Companys average price realization for natural gas was
$2.71 per Mcf, excluding the realized gain or loss on commodity
derivatives. (See Note 6).
The Company has grown its natural gas and oil production
significantly over the past three years and management believes
it has the ability to continue growing production by drilling
already identified locations on its leases in Wyoming. The
Company delivered 30% production growth on an Mcfe basis during
the quarter ended June 30, 2009 as compared to the same
quarter in 2008.
The Company currently conducts operations exclusively in the
United States. Substantially all of the oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented reflect only the Companys proportionate
interest in such activities. Inflation has not had a material
impact on the Companys results of operations and is not
expected to have a material impact on the Companys results
of operations in the future.
In 2008 and the first half of 2009, we saw significant changes
in the business environment in which we operate, including
severe economic uncertainty, increasing market volatility and
continued tightening of credit markets. These market conditions
contributed to record high commodity prices during most of 2008
and nearly unprecedented drops in these commodity prices in the
second half of 2008 and the first half of 2009. We believe we
are well positioned to weather the current economic downturn
because of our status as a low cost operator in the industry and
our financial flexibility. Although we expect that our net cash
provided by operating activities may be negatively affected by
general economic conditions, we believe that we will continue to
generate strong cash flow from operations, which, along with our
available cash, will provide sufficient liquidity to allow us to
return value to our shareholders. While it is possible that we
may not have access to the credit markets on acceptable terms,
we expect to rely on our available cash, our existing credit
facility and the cash we generate from our operations to meet
our obligations and fund our capital expenditures and operations
over the next twelve months. A continued, long-term disruption
in the credit markets could make financing more expensive or
unavailable, which could have a material adverse effect on our
operations.
Rockies Express Pipeline. In December 2005,
the Company agreed to become an anchor shipper on the Rockies
Express Pipeline (REX) securing pipeline
infrastructure providing sufficient capacity to transport a
portion of our natural gas production away from southwest
Wyoming and to provide for reasonable basis differentials for
our natural gas in the future. The Companys commitment
involves capacity of 200,000 MMBtu per day of natural gas
for a term of 10 years (beginning in the first quarter of
2008 when REX West became operational), and the
Company is obligated to pay REX certain demand charges related
to its rights to hold this firm transportation capacity as an
anchor shipper.
The pipeline is being built in two phases: REX West
(Wyoming to Missouri in service) and REX
East (Missouri to Ohio under construction). The REX
partners have recently updated guidance on the timing for
completion of various portions of REX East. As of
June 29, 2009, REX announced that service began on the
portion of the REX East pipeline from Audrain
County, Missouri to the Lebanon Hub in
19
Warren County, Ohio with capacity up to 1.8 billion cubic
feet of natural gas per day. This section of REX
East includes interconnects to NGPL, Ameren, Trunkline,
Midwestern Gas Transmission, Panhandle Eastern, Texas Eastern,
Dominion transmission and Columbia Gas with future interconnects
to Texas Gas, ANR, Citizens and Vectren. REX further advised
that the balance of the REX East pipeline eastward
to Clarington, Ohio is expected to be placed into service by
November 1, 2009.
Derivative Instruments and Hedging
Activities. The Company relies on derivative
instruments to manage its exposure to commodity price risk. The
Company enters into fixed price to index price swap agreements
in order to mitigate its commodity price exposure on a portion
of its natural gas production. The natural gas reference prices
of these commodity derivative contracts are typically referenced
to natural gas index prices as published by independent third
parties. The Company also utilizes 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
SFAS No. 133.
Effective November 3, 2008, the Company has changed its
method of accounting for natural gas commodity derivatives to
reflect unrealized gains and losses on commodity derivative
contracts in the income statement rather than on the balance
sheet. The Company has historically followed hedge accounting
for its natural gas hedges. Under this accounting method, the
unrealized gain or loss on qualifying cash flow hedges
(calculated on a mark to market basis, net of tax) was recorded
on the balance sheet in stockholders equity as accumulated
other comprehensive income (loss). When an unrealized hedging
gain or loss was realized upon contract expiration, it was
reclassified into earnings through inclusion in natural gas
sales revenues. The Company will continue to record the fair
value of its commodity derivatives as an asset or liability on
the Consolidated Balance Sheets, but will record the changes in
the fair value of its commodity derivatives in the Consolidated
Statements of Operations as an unrealized gain or loss on
commodity derivatives. There will be no resulting effect on
overall cash flow, total assets, total liabilities or total
stockholders equity, and there is no impact on any of the
financial covenants under the Companys Senior Credit
Facility, 2008 Senior Notes or 2009 Senior Notes (See
Note 3).
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provides operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010.
Fair Value Measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair value on a recurring basis, primarily our commodity
derivatives, with no material impact on consolidated results of
operations, financial position or liquidity. See Note 7 for
additional information. For those non-financial assets and
liabilities measured or disclosed at fair value on a
non-recurring basis, primarily asset retirement obligations,
SFAS No. 157-2
was effective January 1, 2009. Implementation of this
portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at measurement date and establishes a three level hierarchy for
measuring fair value. The valuation assumptions utilized to
measure the fair value of the Companys 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.
20
The fair values summarized below were determined in accordance
with the requirements of SFAS No. 157. In addition, we
aligned the categories below with the Level 1, 2, and 3
fair value measurements as defined by SFAS No. 157.
The balance of net unrealized gains and losses recognized for
our energy-related derivative instruments at June 30, 2009
is summarized in the following table based on the inputs used to
determine fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1(a)
|
|
|
Level 2(b)
|
|
|
Level 3(c)
|
|
|
Total
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
125,652
|
|
|
$
|
|
|
|
$
|
125,652
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
2,441
|
|
|
$
|
|
|
|
$
|
2,441
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
3,665
|
|
|
$
|
|
|
|
$
|
3,665
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
72,592
|
|
|
$
|
|
|
|
$
|
72,592
|
|
|
|
|
(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 initial
estimated retirement obligation of properties is recognized as a
liability, with an associated increase in oil and gas properties
for the asset retirement cost. Accretion expense is recognized
over the estimated productive life of the related assets. If the
fair value of the estimated asset retirement obligation changes,
an adjustment is recorded to both the asset retirement
obligation and the asset retirement cost. Revisions in estimated
liabilities can result from revisions of estimated inflation
rates, changes in service and equipment costs and changes in the
estimated timing of settling asset retirement obligations.
Share-Based Payment Arrangements. The Company
applies Statement of Financial Accounting Standards No. 123
(revised 2004), Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair
values. Share-based compensation expense recognized under
SFAS No. 123R for the six months ended June 30,
2009 and 2008 was $4.8 million and $2.8 million,
respectively. At June 30, 2009, there was $6.5 million
of total unrecognized compensation cost related to non-vested
share-based compensation arrangements granted under stock option
plans. That cost is expected to be recognized over a weighted
average period of 1.2 years. See Note 4 for additional
information.
SFAS No. 123R requires companies to estimate the fair
value of share-based payment awards on the date of grant using
an option-pricing model. The Company utilized a Black-Scholes
option pricing model to measure the fair value of stock options
granted to employees. The value of the portion of the award that
is ultimately expected to vest is recognized as expense over the
requisite service period in the Companys Consolidated
Statement of Operations. The Companys determination of
fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to, the Companys expected stock price
volatility over the term of the awards and actual and projected
employee stock option exercise behaviors.
Write-down of oil and gas properties. The
Company uses the full cost method of accounting for oil and gas
operations whereby all costs associated with the exploration for
and development of oil and gas reserves are capitalized on a
country-by-country
basis. Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells and overhead charges directly related to acquisition,
exploration and development activities. Substantially all of the
oil and gas activities are conducted jointly with others and,
accordingly, the amounts reflect only the Companys
proportionate interest in such activities.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test
21
is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly on a
country-by-country
basis utilizing prices in effect on the last day of the quarter.
SEC
regulation S-X
Rule 4-10 states
that if prices in effect at the end of a quarter are the result
of a temporary decline and prices improve prior to the issuance
of the financial statements, the increased price may be applied
in the computation of the ceiling test. The ceiling limits such
pooled costs to the aggregate of the present value of future net
revenues attributable to proved crude oil and natural gas
reserves discounted at 10% plus the lower of cost or market
value of unproved properties less any associated tax effects. If
such capitalized costs exceed the ceiling, the Company will
record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down will reduce earnings in
the period of occurrence and result in lower DD&A expense
in future periods. A write-down may not be reversed in future
periods, even though higher oil and natural gas prices may
subsequently increase the ceiling.
During the first quarter of 2009, the Company recorded a
$1.0 billion ($673.0 million net of tax) non-cash
write-down of the carrying value of the Companys proved
oil and gas properties as of March 31, 2009, as a result of
the ceiling test limitations, which is reflected as write-down
of oil and gas properties in the accompanying consolidated
statements of operations. The ceiling test was calculated based
on March 31, 2009 wellhead prices of $2.47 per Mcf for
natural gas and $33.91 per barrel for condensate.
The calculation of the ceiling test is based upon estimates of
proved reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves, in projecting the
future rates of production and in the timing of development
activities. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate
may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and
natural gas that are ultimately recovered.
RESULTS
OF OPERATIONS
QUARTER
ENDED JUNE 30, 2009 VS. QUARTER ENDED JUNE 30,
2008
During the quarter ended June 30, 2009, production
increased 30% on a gas equivalent basis to 44.5 Bcfe from
34.3 Bcfe for the same quarter in 2008 attributable to the
Companys successful drilling activities during 2008 and in
the first six months of 2009. Realized natural gas prices,
including realized gain and loss on commodity derivatives,
decreased 37% to $5.04 per Mcf in the second quarter of 2009 as
compared to $8.06 for the same quarter of 2008. During the three
months ended June 30, 2009, the Companys average
price for natural gas was $2.71 per Mcf, excluding realized
gains and losses on commodity derivatives. The decrease in
average natural gas prices partially offset by the increase in
production contributed to a 58% decrease in revenues to
$130.3 million as compared to $308.2 million in 2008.
Lease operating expense (LOE) increased to
$10.1 million during the second quarter of 2009 compared to
$8.6 million during the same period in 2008 due primarily
to increased production volumes during the quarter ended
June 30, 2009. On a unit of production basis, LOE costs
decreased to $0.23 per Mcfe at June 30, 2009 compared to
$0.25 per Mcfe at June 30, 2008 largely as a result of
increased production volumes and a higher mix of Ultra operated
production during the quarter ended June 30, 2009.
During the three months ended June 30, 2009, production
taxes were $12.7 million compared to $35.8 million
during the same period in 2008, or $0.29 per Mcfe, compared to
$1.04 per Mcfe. The decrease in per unit taxes is attributable
to decreased sales revenues as a result of lower realized gas
prices during the quarter ended June 30, 2009 as compared
to the same period in 2008. Production taxes are calculated
based on a percentage of revenue from production.
Gathering fees increased to $11.6 million for the three
months ended June 30, 2009 compared to $8.8 million
during the same period in 2008 largely due to increased
production volumes. On a per unit basis, gathering fees remained
flat at $0.26 per Mcfe for the three months ended June 30,
2009 as compared to the same period in 2008.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its
22
natural gas, the Company incurred firm transportation charges
totaling $13.2 million for the quarter ended June 30,
2009 as compared to $12.0 million for the same period in
2008 in association with REX Pipeline transportation charges. On
a per unit basis, transportation charges decreased to $0.30 per
Mcfe (on total company volumes) for the three months ended
June 30, 2009 as compared to $0.35 per Mcfe (on total
company volumes) for the same period in 2008 as a result of
increased production volumes.
Depletion, depreciation and amortization (DD&A)
expenses increased to $45.0 million during the three months
ended June 30, 2009 from $42.8 million for the same
period in 2008, attributable to increased production volumes
partially offset by a lower depletion rate due mainly to a lower
depletable base as a result of the ceiling test write-down
during the first quarter of 2009. On a unit basis, DD&A
decreased to $1.01 per Mcfe for the quarter ended June 30,
2009 from $1.25 for the quarter ended June 30, 2008. The
Company recorded a $1.0 billion non-cash write-down of the
carrying value of the Companys proved oil and gas
properties at March 31, 2009 as a result of ceiling test
limitations. Under the full cost method of accounting, the
ceiling test limits 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. The capitalized costs exceeded the ceiling
limitation at March 31, 2009 and the Company recorded a
write-down to the extent of the excess as a non-cash charge to
earnings. The write-down reduced earnings in first quarter of
2009 and results in lower DD&A expense in future periods.
General and administrative expenses increased to
$5.7 million ($0.13 per Mcfe) for the quarter ended
June 30, 2009 compared to $4.4 million ($0.13 per
Mcfe) for the same period in 2008. The increase in general and
administrative expenses is primarily attributable to increased
headcount and related compensation.
Interest expense increased to $9.9 million during the
quarter ended June 30, 2009 compared to $4.5 million
during the same period in 2008 as a result of increased
borrowings. At June 30, 2009, the Company had
$764.0 million in borrowings outstanding.
During the quarter ended June 30, 2009, the Company
recognized $99.2 million related to realized gain on
commodity derivatives and $159.9 million in unrealized loss
on commodity derivatives as compared to $14.1 million
related to realized loss on commodity derivatives and
$2.5 million in unrealized gain on commodity derivatives
during the quarter ended June 30, 2008. The realized gain
or loss on commodity derivatives relates to actual amounts
received or paid under these derivative contracts while the
unrealized gain or loss on commodity derivatives represents the
change in the fair market value of these derivative instruments.
The Company recognized a loss before income taxes of
$39.0 million for the quarter ended June 30, 2009
compared with income of $179.9 million for the same period
in 2008. The decrease in earnings is primarily a result of
decreased natural gas prices and non-cash, unrealized losses on
commodity derivatives partially offset by increased production
during the three months ended June 30, 2009 as compared to
the same period in 2008.
The income tax benefit recognized for the quarter ended
June 30, 2009 was $13.5 million compared with an
income tax provision of $63.5 million for the three months
ended June 30, 2008 due to a net loss during the quarter
ended June 30, 2009 primarily as a result of non-cash,
unrealized losses on commodity derivatives.
For the three months ended June 30, 2009, the Company
recognized a net loss of $25.5 million or $0.17 per diluted
share as compared with net income of $116.9 million or
$0.74 per diluted share for the same period in 2008 primarily
attributable to decreased natural gas prices and non-cash,
unrealized losses on commodity derivatives partially offset by
increased production during the three months ended June 30,
2009 as compared to the same period in 2008.
SIX
MONTHS ENDED JUNE 30, 2009 VS. SIX MONTHS ENDED JUNE 30,
2008
During the six months ended June 30, 2009, production
increased 27% on a gas equivalent basis to 86.6 Bcfe from
68.4 Bcfe for the same period in 2008 attributable to the
Companys successful drilling activities during 2008 and in
the first six months of 2009. Realized natural gas prices,
including realized gain
23
and loss on commodity derivatives, decreased 39% to $4.76 per
Mcf during the six months ended June 30, 2009 as compared
to $7.86 for the same period in 2008. During the six months
ended June 30, 2009, the Companys average price for
natural gas was $3.31 per Mcf, excluding realized gains and
losses on commodity derivatives. The decrease in average natural
gas prices partially offset by the increase in production
contributed to a 49% decrease in revenues for the six months
ended June 30, 2009 to $298.3 million as compared to
$579.4 million in 2008.
Lease operating expense (LOE) increased to
$20.4 million during the six months ended June 30,
2009 compared to $19.3 million during the same period in
2008 due primarily to increased production volumes and partially
offset by decreased costs related to water disposal on
non-operated properties during the six months ended
June 30, 2009. On a unit of production basis, LOE costs
decreased to $0.24 per Mcfe at June 30, 2009 compared to
$0.28 per Mcfe at June 30, 2008 as a result of increased
production volumes and a higher mix of Ultra operated production
during the six months ended June 30, 2009.
During the six months ended June 30, 2009, production taxes
were $30.1 million compared to $66.7 million during
the same period in 2008, or $0.35 per Mcfe, compared to $0.98
per Mcfe. The decrease in per unit taxes is attributable to
decreased sales revenues as a result of lower realized gas
prices during the six months ended June 30, 2009 as
compared to the same period in 2008. Production taxes are
calculated based on a percentage of revenue from production.
Gathering fees increased to $22.4 million for the six
months ended June 30, 2009 compared to $18.8 million
during the same period in 2008 largely due to increased
production volumes. On a per unit basis, gathering fees
decreased to $0.26 per Mcfe for the six months ended
June 30, 2009 as compared to $0.27 per Mcfe for the same
period in 2008.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred firm transportation charges totaling $26.5 million
for the period ended June 30, 2009 as compared to
$21.7 million for the same period in 2008 in association
with REX Pipeline transportation charges. On a per unit basis,
transportation charges decreased to $0.31 per Mcfe (on total
company volumes) for the six months ended June 30, 2009 as
compared to $0.32 per Mcfe (on total company volumes) for the
same period in 2008.
DD&A increased to $105.6 million during the period
ended June 30, 2009 from $85.0 million for the same
period in 2008, attributable to increased production volumes,
partially offset by a lower depletion rate due mainly to a lower
depletable base as a result of the ceiling test write-down
during the first quarter of 2009. On a unit basis, DD&A
decreased to $1.22 per Mcfe at June 30, 2009 from $1.24 at
June 30, 2008. The Company recorded a $1.0 billion
non-cash write-down of the carrying value of the Companys
proved oil and gas properties at March 31, 2009 as a result
of ceiling test limitations. Under the full cost method of
accounting, the ceiling test limits 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. The
capitalized costs exceeded the ceiling limitation at
March 31, 2009 and the Company recorded a write-down to the
extent of the excess as a non-cash charge to earnings. The
write-down reduced earnings in first quarter of 2009 and results
in lower DD&A expense in future periods.
General and administrative expenses increased to
$10.2 million ($0.12 per Mcfe) for the period ended
June 30, 2009 compared to $8.8 million ($0.13 per
Mcfe) for the same period in 2008. The increase in general and
administrative expenses is primarily attributable to increased
headcount and related compensation.
Interest expense increased to $17.2 million during the
period ended June 30, 2009 compared to $9.8 million
during the same period in 2008 as a result of increased
borrowings during the period ended June 30, 2009. At
June 30, 2009, the Company had $764.0 million in
borrowings outstanding.
Other expense increased to $3.1 million as of June 30,
2009 primarily as a result of rig termination payments during
the period ended June 30, 2009.
24
During the six months ended June 30, 2009, the Company
recognized $119.6 million and $26.2 million related to
realized gain on commodity derivatives and unrealized gain on
commodity derivatives, respectively as compared to
$14.1 million related to realized loss on commodity
derivatives and $25.2 million in unrealized loss on
commodity derivatives during the six months ended June 30,
2008. The realized gain or loss on commodity derivatives relates
to actual amounts received or paid under these derivative
contracts while the unrealized gain or loss on commodity
derivatives represents the change in the fair market value of
these derivative instruments.
The Company recognized a loss before income taxes of
$828.5 million for the six months ended June 30, 2009
compared with income of $310.3 million for the same period
in 2008. The decrease in earnings is primarily a result of the
non-cash write-down of oil and gas properties associated with
the ceiling test limitation, decreased natural gas prices
partially offset by increased production and gains on commodity
derivatives during the six months ended June 30, 2009 as
compared to the same period in 2008.
The income tax benefit recognized for the six months ended
June 30, 2009 was $290.4 million compared with an
income tax provision of $110.5 million for the six months
ended June 30, 2008 due to a net loss during the six months
ended June 30, 2009 primarily as a result of the non-cash
write-down of oil and gas properties associated with the ceiling
test limitation.
For the six months ended June 30, 2009, the Company
recognized a net loss of $538.1 million or $3.56 per
diluted share as compared with net income of $200.2 million
or $1.27 per diluted share for the same period in 2008 primarily
attributable to the non-cash write-down of oil and gas
properties associated with the ceiling test limitation,
decreased natural gas prices partially offset by increased
production and gains on commodity derivatives during the six
months ended June 30, 2009 as compared to the same period
in 2008.
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. GAAP. In addition, application of generally
accepted accounting principles requires the use of estimates,
judgments and assumptions that affect the reported amounts of
assets and liabilities as of the date of the financial
statements as well as the revenues and expenses reported during
the period. Changes in these estimates, judgments and
assumptions will occur as a result of future events, and,
accordingly, actual results could differ from amounts estimated.
LIQUIDITY
AND CAPITAL RESOURCES
During the six month period ended June 30, 2009, the
Company relied on cash provided by operations along with
borrowings under the senior credit facility and the issuance of
the 2009 Senior Notes to finance its capital expenditures. The
Company participated in the drilling of 165 wells in
Wyoming and Pennsylvania. For the six month period ended
June 30, 2009, net capital expenditures were
$382.4 million. At June 30, 2009, the Company reported
a cash position of $9.3 million compared to
$60.3 million at June 30, 2008. Working capital at
June 30, 2009 was $19.4 million compared to a deficit
of $136.7 million at June 30, 2008. At June 30,
2009, we had $229.0 million in outstanding borrowings and
$271.0 million of available borrowing capacity under our
credit facility. In addition, the Company had
$300.0 million and $235.0 million outstanding under
its 2008 Senior Notes and 2009 Senior Notes, respectively (See
Note 3). Other long-term obligations of $29.4 million
at June 30, 2009 is comprised of items payable in more than
one year, primarily related to production taxes and our asset
retirement obligation.
The Companys positive cash provided by operating
activities, along with availability under the senior credit
facility, are projected to be sufficient to fund the
Companys budgeted capital expenditures for 2009, which are
currently projected to be $735.0 million. Of the
$735.0 million budget, the Company plans to allocate
approximately 85% to Wyoming and 15% to Pennsylvania.
Bank indebtedness. The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the
25
amount of its commitment as requested by the Company. In the
event the existing banks increase their commitment to an amount
less than the requested commitment amount, then it would be
necessary to add new financial institutions to the credit
facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (100.0 basis points
per annum as of June 30, 2009).
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At June 30, 2009, we were in compliance with all
of our debt covenants under our credit facility.
Senior Notes, due 2016 and 2019: On
March 5, 2009, our wholly-owned subsidiary, Ultra
Resources, Inc., issued $235.0 million Senior Notes
pursuant to a Master Note Purchase Agreement dated March 6,
2008 as supplemented by a First Supplement thereto dated
March 5, 2009 between the Company and the purchasers of the
2009 Senior Notes. The 2009 Senior Notes rank pari passu with
the Companys bank credit facility. Payment of the 2009
Senior Notes is guaranteed by Ultra Petroleum Corp. and UP
Energy Corporation. Of the 2009 Senior Notes,
$173.0 million are 7.77% senior notes due
March 1, 2019 and $62.0 million are 7.31% senior
notes due March 1, 2016.
Proceeds from the sale of the 2009 Senior Notes were used to
repay bank debt, but did not reduce the borrowings available to
us under the revolving credit facility.
The 2009 Senior Notes are pre-payable in whole or in part at any
time. The 2009 Senior Notes are subject to representations,
warranties, covenants and events of default customary for a
senior note financing. If payment default occurs, any note
holder may accelerate its notes; if a non-payment default
occurs, holders of 51% of the outstanding principal amount of
the 2009 Senior Notes may accelerate all the 2009 Senior Notes.
At June 30, 2009, we were in compliance with all of our
debt covenants under the 2009 Senior Notes.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes pursuant
to a Master Note Purchase Agreement between the Company and the
purchasers of the Notes. The 2008 Senior Notes rank pari passu
with the Companys bank credit facility. Payment of the
2008 Senior Notes is guaranteed by Ultra Petroleum Corp. and UP
Energy Corporation. Of the 2008 Senior Notes,
$200.0 million are 5.92% senior notes due
March 1, 2018 and $100.0 million are 5.45% senior
notes due March 1, 2015.
Proceeds from the sale of the 2008 Senior Notes were used to
repay bank debt, but did not reduce the borrowings available to
us under the revolving credit facility.
The 2008 Senior Notes are pre-payable in whole or in part at any
time. The 2008 Senior Notes are subject to representations,
warranties, covenants and events of default customary for a
senior note financing. If payment default occurs, any note
holder may accelerate its notes; if a non-payment default
occurs, holders of 51% of the outstanding principal amount of
the 2008 Senior Notes may accelerate all the 2008 Senior Notes.
At June 30, 2009, we were in compliance with all of our
debt covenants under the 2008 Senior Notes.
Operating Activities. During the six months
ended June 30, 2009, net cash provided by operating
activities was $240.4 million, a 40% decrease from
$403.3 million for the same period in 2008. The decrease in
net cash provided by operating activities was largely
attributable to the decrease in realized natural gas prices
partially offset by increased production during the six months
ended June 30, 2009 as compared to the same period in 2008.
Investing Activities. During the six months
ended June 30, 2009, net cash used in investing activities
was $441.6 million as compared to $372.7 million for
the same period in 2008. The increase in net cash used in
investing activities is largely due to the timing of payments
associated with capital costs incurred during
26
2008 and paid during the first six months of 2009 partially
offset by decreased capital expenditures associated with the
Companys drilling activities in 2009 as compared to 2008.
Financing Activities. During the six months
ended June 30, 2009, net cash provided by financing
activities was $196.3 million as compared to
$19.0 million for the same period in 2008. The increase in
cash provided by net financing activities is primarily
attributable to increased net borrowings of $194.0 million
during the six months ended June 30, 2009 as compared to
net borrowings of $10.0 million during the same period in
2008.
Recent Disruption in the Credit Markets. We
are experiencing unprecedented disruption in the U.S. and
international credit markets. These disruptions have resulted in
greater volatility, less liquidity, widening of credit spreads
and more limited availability of financing. While we believe our
cash on hand and availability under our credit facility will be
sufficient to finance our capital expenditures and operations
over the next twelve months, continued, long-term disruption in
the credit markets could make financing more expensive or
unavailable, which could have a material adverse effect on our
operations.
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of June 30, 2009.
CAUTIONARY
STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding our financial position,
estimated quantities and net present values of reserves,
business strategy, plans and objectives of the Companys
management for future operations, covenant compliance and those
statements preceded by, followed by or that otherwise include
the words believe, expects,
anticipates, intends,
estimates, projects, target,
goal, plans, objective,
should, or similar expressions or variations on such
expressions are forward-looking statements. The Company can give
no assurances that the assumptions upon which such
forward-looking statements are based will prove to be correct
nor can the Company assure adequate funding will be available to
execute the Companys planned future capital program.
Other risks and uncertainties include, but are not limited to,
fluctuations in the price the Company receives for oil and gas
production, reductions in the quantity of oil and gas sold due
to increased industry-wide demand
and/or
curtailments in production from specific properties due to
mechanical, marketing or other problems, operating and capital
expenditures that are either significantly higher or lower than
anticipated because the actual cost of identified projects
varied from original estimates
and/or from
the number of exploration and development opportunities being
greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates.
We are also subject to risks associated with the current
unprecedented volatility in the financial markets, including the
duration of the crisis and effectiveness of government
solutions. See the Companys annual report on
Form 10-K
for the year ended December 31, 2008 for additional risks
related to the Companys business.
ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The Companys major market risk exposure is in the pricing
applicable to its natural gas and oil production. Realized
pricing is currently driven primarily by the prevailing price
for the Companys Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable. Pricing volatility is expected
to continue. Realized natural gas prices are derived from the
financial statements which include the effects of realized gains
and losses on commodity derivatives.
27
The Company relies on 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 Company
enters into fixed price to index price swap agreements in order
to mitigate its commodity price exposure on a portion of its
natural gas production. The natural gas reference prices of
these commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties such as Inside FERC Gas Market Report. The
Company also utilizes 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 SFAS No. 133.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
Unrealized gains or losses on commodity derivatives represents
the non-cash change in the fair value of these derivative
instruments and does not impact operating cash flows on the
Consolidated Statements of Cash Flows.
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The net
gain or loss in accumulated other comprehensive income at
November 3, 2008 will remain on the balance sheet and the
respective months gains or losses will continue to be
reclassified from accumulated other comprehensive income to
earnings as the counterparty settlements affect earnings
(January through December 2009). It is still considered probable
that the original forecasted transactions will occur; therefore,
the net gain or loss in accumulated other comprehensive income
shall not be immediately reclassified into earnings. As a result
of the de-designation on November 3, 2008, the company no
longer has any derivative instruments which qualify for cash
flow hedge accounting.
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provides operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months from April
2009 through December 2010.
At June 30, 2009, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price. See Note 7 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
Volume-
|
|
|
Average
|
|
|
June 30,
|
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
|
Price/MMBTU
|
|
|
2009
|
|
|
Swap
|
|
Mid Continent
|
|
July 2009 October 2009
|
|
|
130,000
|
|
|
$
|
4.99
|
|
|
$
|
26,519
|
|
Swap
|
|
NW Rockies
|
|
July 2009 October 2009
|
|
|
130,000
|
|
|
$
|
5.85
|
|
|
$
|
48,166
|
|
Swap
|
|
NW Rockies
|
|
November 2009
|
|
|
50,000
|
|
|
$
|
3.53
|
|
|
$
|
(220
|
)
|
Swap
|
|
NW Rockies
|
|
July 2009 December 2009
|
|
|
100,000
|
|
|
$
|
5.65
|
|
|
$
|
43,272
|
|
Swap
|
|
NW Rockies
|
|
April 2010 October 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
1,499
|
|
Swap
|
|
NW Rockies
|
|
January 2010 December 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
(2,432
|
)
|
Swap
|
|
NW Rockies
|
|
January 2010 December 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
(60,436
|
)
|
Swap
|
|
Northeast
|
|
January 2010 December 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
(4,532
|
)
|
28
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the three and six months ended
June 30, 2009 and 2008 (refer to Note 1(o) for details
of unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Six Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain (loss) on derivatives(1)
|
|
$
|
99,205
|
|
|
$
|
(14,119
|
)
|
|
$
|
119,561
|
|
|
$
|
(14,119
|
)
|
Unrealized gain (loss) on commodity derivatives(1)
|
|
$
|
(159,903
|
)
|
|
$
|
2,523
|
|
|
$
|
26,169
|
|
|
$
|
(25,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on commodity derivatives
|
|
$
|
(60,698
|
)
|
|
$
|
(11,596
|
)
|
|
$
|
145,730
|
|
|
$
|
(39,269
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain (loss) on commodity derivatives in the
Consolidated Statements of Operations. |
ITEM 4
CONTROLS AND PROCEDURES
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
We have performed an evaluation under the supervision and with
the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures, as
defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act). Our disclosure controls and procedures are the
controls and other procedures that we have designed to ensure
that we record, process, accumulate and communicate information
to our management, including our Chief Executive Officer and
Chief Financial Officer, to allow timely decisions regarding
required disclosures and submissions within the time periods
specified in the SECs rules and forms. All internal
control systems, no matter how well designed, have inherent
limitations. Therefore, even those determined to be effective
can provide only a reasonable assurance with respect to
financial statement preparation and presentation. Based on the
evaluation, our management, including our Chief Executive
Officer and Chief Financial Officer, concluded that our
disclosure controls and procedures were effective as of
June 30, 2009. There were no changes in our internal
control over financial reporting during the six months ended
June 30, 2009 that have materially affected or are
reasonably likely to affect, our internal control over financial
reporting.
PART II
OTHER INFORMATION
|
|
ITEM 1.
|
LEGAL
PROCEEDINGS
|
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such
pending or threatened litigation is not likely to have a
material adverse effect on the Companys financial
position, or results of operations.
There have been no material changes with respect to the risk
factors disclosed in our Annual Report on
Form 10-K
for the fiscal year ended December 31, 2008.
|
|
ITEM 2.
|
CHANGES
IN SECURITIES AND USE OF PROCEEDS
|
None.
|
|
ITEM 3.
|
DEFAULTS
IN SENIOR SECURITIES
|
None.
29
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
|
The Company held its annual meeting on May 21, 2009. At the
annual meeting, the entire board of directors of the Company was
elected. The votes cast for each of the directors proposed by
the Companys definitive proxy statement on
Schedule 14A was as follows:
|
|
|
|
|
|
|
Michael D. Watford
|
|
|
|
|
|
124,094,305 voted in favor, zero voted against, and 3,033,838
withheld.
|
W. Charles Helton
|
|
|
|
|
|
124,789,073 voted in favor, zero voted against, and 2,339,070
withheld.
|
Stephen J. McDaniel
|
|
|
|
|
|
124,427,061 voted in favor, zero voted against, and 2,701,082
withheld.
|
Roger A. Brown
|
|
|
|
|
|
124,313,512 voted in favor, zero voted against, and 2,814,631
withheld.
|
Robert E. Rigney
|
|
|
|
|
|
124,378,991 voted in favor, zero voted against, and 2,749,152
withheld.
|
The shareholders of the Company approved the appointment of
Ernst & Young, LLP as the Companys independent
auditors for 2009. There were 126,780,925 votes in favor of
approval of the appointment of Ernst & Young, LLP as
the Companys auditors, zero votes against and 354,168
votes withheld.
In accordance with the rules of the SEC and Yukon law, a
representative of the shareholder proponent must be in
attendance to present the proposal. Such representative was not
in attendance when the proposal was presented.
A total of 127,135,094 shares were voted by
210 shareholders, representing 84% of the Companys
outstanding shares.
|
|
ITEM 5.
|
OTHER
INFORMATION
|
None.
|
|
ITEM 6.
|
EXHIBITS AND
REPORTS ON
FORM 8-K
-
|
(a) Exhibits
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the Companys
Quarterly Report on Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on Form 10Q
for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the
Companys Report on Form 10-K/A for the period ended
December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly Report
on Form 10Q for the period ended June 30, 2001.)
|
|
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.
|
30
|
|
|
|
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
101
|
.DEF**
|
|
XBRL Taxonomy Extension Definition.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
ULTRA PETROLEUM CORP.
|
|
|
|
By:
|
/s/ Michael
D. Watford
|
Name: Michael D. Watford
|
|
|
|
Title:
|
Chairman, President and
|
Chief Executive Officer
Date: August 4, 2009
|
|
|
|
By:
|
/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
|
Title:
|
Chief Financial Officer
|
Date: August 4, 2009
32
EXHIBIT INDEX
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
101
|
.DEF**
|
|
XBRL Taxonomy Extension Definition.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
33