e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
September 30,
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)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). YES o NO þ
The number of common shares, without par value, of Ultra
Petroleum Corp., outstanding as of October 22, 2009 was
151,442,194.
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 Nine Months
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Ended September 30,
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Ended September 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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135,538
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$
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266,573
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$
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409,446
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$
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793,140
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Oil Sales
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19,626
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31,054
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44,012
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83,863
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Total operating revenues
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155,164
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297,627
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453,458
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877,003
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Expenses:
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Lease operating expenses
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9,741
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8,501
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30,128
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27,800
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Production taxes
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15,220
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31,625
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45,309
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98,336
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Gathering fees
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11,389
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8,857
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33,753
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27,621
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Transportation charges
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16,284
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11,431
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42,824
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33,101
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Depletion and depreciation
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46,367
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45,652
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152,002
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130,681
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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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5,130
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4,242
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15,354
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13,036
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Total operating expenses
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104,131
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110,308
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1,356,370
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330,575
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Operating income (loss)
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51,033
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187,319
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(902,912
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)
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546,428
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Other income (expense), net:
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Interest expense
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(9,744
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(5,183
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(26,938
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(14,997
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(Loss) gain on commodity derivatives
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(55,428
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)
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58,117
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90,301
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18,848
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Other income (expense) net
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193
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92
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(2,925
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783
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Total other (expense) income, net
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(64,979
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53,026
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60,438
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4,634
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(Loss) income before income tax (benefit) provision
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(13,946
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240,345
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(842,474
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551,062
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Income tax (benefit) provision
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(5,616
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91,370
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(296,029
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201,880
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Net (loss) income
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$
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(8,330
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$
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148,975
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$
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(546,445
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$
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349,182
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Net (loss) income per common share basic
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$
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(0.06
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$
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0.98
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$
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(3.61
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$
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2.29
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Net (loss) income per common share fully diluted
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$
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(0.06
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$
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0.95
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$
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(3.61
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$
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2.22
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Weighted average common shares outstanding basic
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151,441
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152,217
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151,337
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152,592
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Weighted average common shares outstanding fully
diluted
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151,441
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156,072
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151,337
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157,326
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See accompanying notes to consolidated financial statements.
3
ULTRA
PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
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September 30,
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December 31,
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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, except share data)
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ASSETS
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Current Assets:
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Cash and cash equivalents
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$
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12,994
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$
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14,157
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Restricted cash
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1,683
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2,727
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Accounts receivable
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116,936
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126,710
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Derivative assets
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30,292
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39,939
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Inventory
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4,763
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8,522
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Prepaid drilling costs and other current assets
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3,739
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6,163
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Total current assets
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170,407
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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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1,705,476
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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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5,994
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5,770
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Deferred financing costs and other
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9,232
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3,648
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Total assets
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$
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1,891,109
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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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110,892
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$
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163,902
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Production taxes payable
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73,651
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61,416
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Derivative liabilities
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35,746
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1,712
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Capital cost accrual
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68,488
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120,543
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Total current liabilities
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288,777
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347,573
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Long-term debt
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730,000
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570,000
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Deferred income tax liability
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188,407
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503,597
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Long-term derivative liabilities
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93,718
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Other long-term obligations
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38,345
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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 151,442,194 and
151,232,545, respectively
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363,268
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346,832
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Treasury stock
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(30,934
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(45,740
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Retained earnings
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215,971
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774,117
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Accumulated other comprehensive income
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3,557
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15,577
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Total shareholders equity
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551,862
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1,090,786
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Total liabilities and shareholders equity
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$
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1,891,109
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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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Nine Months Ended
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September 30,
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2009
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2008
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(Unaudited)
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(Amounts in thousands
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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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(546,445
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)
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$
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349,182
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Adjustments to reconcile net (loss) income to cash provided by
operating activities:
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Depletion and depreciation
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152,002
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130,681
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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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(303,724
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)
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197,350
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Unrealized loss (gain) on commodity derivatives
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118,879
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(15,765
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)
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Excess tax benefit from stock based compensation
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(4,966
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)
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(65,932
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)
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Stock compensation
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7,623
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4,860
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Other
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881
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(100
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Net changes in operating assets and liabilities:
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Restricted cash
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1,044
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(97
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Accounts receivable
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9,774
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(14,496
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Prepaid expenses and other
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2,740
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(2,112
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Other non-current assets
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(4,584
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)
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Accounts payable, production taxes and accrued liabilities
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(40,898
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)
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100,374
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Other long-term obligations
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(8,557
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)
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35,080
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Current taxes payable
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(10,839
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Net cash provided by operating activities
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420,769
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708,186
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Investing Activities:
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Oil and gas property expenditures
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(536,958
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(678,978
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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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(52,055
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28,689
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Inventory
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3,759
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7,307
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Other
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(703
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Purchase of capital assets
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(932
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(1,098
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Net cash used in investing activities
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(586,889
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(643,440
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)
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Financing activities:
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Borrowings on long-term debt
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810,000
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480,000
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Payments on long-term debt
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(650,000
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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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(285,097
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)
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Excess tax benefit from stock based compensation
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4,966
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65,932
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Proceeds from exercise of options
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1,274
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18,366
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Net cash provided by (used in) financing activities
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164,957
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(44,379
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)
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(Decrease)/increase in cash during the period
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(1,163
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)
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20,367
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Cash and cash equivalents, beginning of period
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14,157
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10,632
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Cash and cash equivalents, end of period
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$
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12,994
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|
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$
|
30,999
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|
|
|
|
|
|
|
|
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.
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|
1.
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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.
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 proved 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 September 30, 2009,
drilling and completion supplies inventory of $4.8 million
primarily includes the cost of pipe and production equipment
that will be utilized during the 2009 and 2010 drilling programs.
(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. From time to time, 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
Financial Accounting Standards Board (FASB)
Accounting Standards Codification (ASC) Topic 815,
Derivatives and Hedging (FASB ASC 815). The Company
does not offset the value of its derivative arrangements with
the same counterparty. (See Note 6).
In March 2008, the FASB updated the requirements for disclosures
about derivative instruments and hedging activities. The updated
requirements are 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; and how derivative instruments
and related hedged items affect
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
financial position, financial performance, and cash flows. The
Company adopted these provisions effective January 1, 2009.
The adoption 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 described in FASB
ASC Topic 740, Income Taxes. In addition, we recognize the
financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely
than not sustain the position following an audit.
(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 components of
basic and diluted net (loss) income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Net (loss) income
|
|
$
|
(8,330
|
)
|
|
$
|
148,975
|
|
|
$
|
(546,445
|
)
|
|
$
|
349,182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
|
|
|
151,441
|
|
|
|
152,217
|
|
|
|
151,337
|
|
|
|
152,592
|
|
Effect of dilutive instruments(1)(2)
|
|
|
|
|
|
|
3,855
|
|
|
|
|
|
|
|
4,734
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
|
|
151,441
|
|
|
|
156,072
|
|
|
|
151,337
|
|
|
|
157,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share basic
|
|
$
|
(0.06
|
)
|
|
$
|
0.98
|
|
|
$
|
(3.61
|
)
|
|
$
|
2.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted (loss) earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per common share fully diluted
|
|
$
|
(0.06
|
)
|
|
$
|
0.95
|
|
|
$
|
(3.61
|
)
|
|
$
|
2.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Due to the net loss for the three months ended
September 30, 2009, 2.9 million shares for options and
restricted stock were anti-dilutive and excluded from the
computation of loss per share. |
|
(2) |
|
Due to the net loss for the nine months ended September 30,
2009, 2.8 million shares for options and 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
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
(k) Accounting for share-based
compensation: The Company measures and recognizes
compensation expense for all share-based payment awards made to
employees and directors, including employee stock options, based
on estimated fair values in accordance with FASB ASC Topic 718,
Compensation Stock Compensation.
(l) Fair Value Accounting. The Company
follows FASB ASC Topic 820, Fair Value Measurements and
Disclosures (FASB ASC 820), which defines fair
value, establishes a framework for measuring fair value in
generally accepted accounting principles, and expands
disclosures about fair value measurements. This statement
applies under other accounting topics that require or permit
fair value measurements. The implementation 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, this respective subtopic of FASB ASC 820,
was effective January 1, 2009. Implementation of this
portion of the standard did not have a material impact on
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
(Loss): Other comprehensive income (loss) is a
term used to define revenues, expenses, gains and losses that
under generally accepted accounting principles impact
Shareholders Equity, excluding transactions with
shareholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Net (loss) income
|
|
$
|
(8,330
|
)
|
|
$
|
148,975
|
|
|
$
|
(546,445
|
)
|
|
$
|
349,182
|
|
Realized (loss) gain on derivative instruments*
|
|
|
(5,960
|
)
|
|
|
55,287
|
|
|
|
(18,520
|
)
|
|
|
17,729
|
|
Tax benefit (expense) on realized (loss) gain on derivative
instruments
|
|
|
2,092
|
|
|
|
(19,406
|
)
|
|
|
6,500
|
|
|
|
(6,223
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive (loss) income
|
|
$
|
(12,198
|
)
|
|
$
|
184,856
|
|
|
$
|
(558,465
|
)
|
|
$
|
360,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 15, 2009, the
FASB issued a proposed Accounting Standards Update
(ASU), Oil and Gas Reserve Estimation and
Disclosures. The proposed ASU would amend FASB ASC Topic 932,
Extractive Activities Oil and Gas (FASB ASC
932) to align the reserve calculation and disclosure
requirements of FASB ASC 932 with the requirements in the SEC
Rule, Modernization of Oil and Gas Reporting Requirements. As
proposed, the ASU would be effective for reporting periods
ending on or after December 31, 2009.
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 is the single source
of authoritative U.S. GAAP. U.S. GAAP is no longer
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 is classified as either
authoritative or non-authoritative based
on its inclusion or exclusion from the Codification.
In April 2009, the FASB updated FASB ASC Topic 320,
Investments Debt and Equity Securities, 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 amendment is effective for interim and annual reporting
periods ending after June 15, 2009. Accordingly, the
Company has adopted these provisions 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:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
3,406,896
|
|
|
$
|
2,809,082
|
|
Less: Accumulated depletion, depreciation and amortization
|
|
|
(1,701,420
|
)
|
|
|
(514,100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,705,476
|
|
|
|
2,294,982
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized*
|
|
|
|
|
|
|
55,544
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,705,476
|
|
|
$
|
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 proved 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:
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Bank indebtedness
|
|
$
|
195,000
|
|
|
$
|
270,000
|
|
Senior notes
|
|
|
535,000
|
|
|
|
300,000
|
|
Other long-term obligations
|
|
|
38,345
|
|
|
|
46,206
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
768,345
|
|
|
$
|
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 September 30, 2009).
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At September 30, 2009, we had $195.0 million in
outstanding borrowings and $305.0 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 September 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 September 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 September 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, the long-term portion of our incentive compensation
plans and our asset retirement obligations.
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
4.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
Ended September 30,
|
|
Ended September 30,
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
Total cost of share-based payment plans
|
|
$
|
4,814
|
|
|
$
|
2,871
|
|
|
$
|
13,247
|
|
|
$
|
7,737
|
|
Amounts capitalized in fixed assets
|
|
$
|
2,009
|
|
|
$
|
767
|
|
|
$
|
5,624
|
|
|
$
|
2,877
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
2,805
|
|
|
$
|
2,104
|
|
|
$
|
7,623
|
|
|
$
|
4,860
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
985
|
|
|
$
|
739
|
|
|
$
|
2,676
|
|
|
$
|
1,706
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model. The
Companys employee stock options have various restrictions
including vesting provisions and restrictions on transfers and
hedging, among others, and are often exercised prior to their
contractual maturity. Expected volatilities used in the fair
value estimates are based on historical volatility of the
Companys stock. The Company uses historical data to
estimate share option exercises, expected term and employee
departure behavior used in the Black-Scholes pricing model.
Groups of employees (executives and non-executives) that have
similar historical behavior are considered separately for
purposes of determining the expected term used to estimate fair
value. The assumptions utilized result from differing pre- and
post-vesting behaviors among executive and non-executive groups.
The risk-free rate for periods within the contractual term of
the share option is based on the U.S. Treasury yield curve
in effect at the time of grant. There were no stock options
granted during the nine months ended September 30, 2009.
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the nine months ended September 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
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(43
|
)
|
|
$
|
51.60 to $78.55
|
|
Exercised
|
|
|
(165
|
)
|
|
$
|
2.04 to $33.57
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2009
|
|
|
4,005
|
|
|
$
|
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 has 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. 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 nine months ended September 30, 2009, the Company
recognized $3.9 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 nine months ended September 30, 2008, the Company
recognized $1.6 million in pre-tax compensation expense
related to the 2006, 2007, and 2008 LTIP Common Stock Awards.
The amounts recognized during the nine months ended
September 30, 2009 assumes that maximum performance
objectives are attained. If the Company ultimately attains these
performance objectives, the associated total compensation,
estimated at September 30, 2009, for each of the three year
performance periods is expected to be approximately
$4.0 million, $3.8 million, and $9.7 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 $9.6 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 become payable and vest
upon distribution is based on the Companys performance
relative to the industry during a three year performance period
beginning January 1, 2008, and ending December 31,
2010, 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 nine months ended September 30, 2009, the Company
recognized $0.6 million in pre-tax compensation expense
related to the 2008 Best in Class Program. For the nine
months ended September 30, 2008 the Company recognized
$0.5 million in pre-tax compensation expense related to the
2008 Best in Class Program. The amount recognized for the
nine months ended September 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 $4.1 million as of
September 30, 2009.
During the quarter ended September 30, 2009, the Company
recorded an income tax benefit of $5.6 million or 40.3% of
the loss before income tax provision. This compares to a
$91.4 million income tax provision or 38.1% of the income
before income tax provision for the quarter ended
September 30, 2008. The effective tax rate increased over
the prior period primarily due to certain reconciling items
related to the filing of the 2008 U.S. Income Tax Return in
September 2009.
During the nine months ended September 30, 2009, the
Company recorded an income tax benefit of $296.0 million or
35.1% of the loss before income tax provision. This compares to
a $201.9 million income tax provision or 36.7% of the
income before income tax provision for the nine months ended
September 30, 2008. The effective tax rate decreased over
the prior period primarily due to withholding taxes paid on
share repurchase transactions during 2008.
|
|
6.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
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 various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010. The natural gas reference prices of these
commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties.
From time to time, the Company 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 FASB ASC
815, Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB ASC
815 requires that all derivatives be recognized on the balance
sheet as either an asset or liability and be measured at fair
value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
15
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At September 30, 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
|
|
September 30,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
Mid Continent
|
|
October 2009
|
|
|
130,000
|
|
|
$
|
4.99
|
|
|
$
|
5,908
|
|
Swap
|
|
NW Rockies
|
|
October 2009
|
|
|
130,000
|
|
|
$
|
5.85
|
|
|
$
|
9,987
|
|
Swap
|
|
NW Rockies
|
|
November 2009
|
|
|
50,000
|
|
|
$
|
3.53
|
|
|
$
|
(1,404
|
)
|
Swap
|
|
NW Rockies
|
|
Oct 2009 Dec 2009
|
|
|
100,000
|
|
|
$
|
5.65
|
|
|
$
|
11,661
|
|
Swap
|
|
NW Rockies
|
|
Apr 2010 Oct 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
(4,266
|
)
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
(11,511
|
)
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
(101,165
|
)
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
(8,382
|
)
|
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 nine months ended
September 30, 2009 and 2008 (refer to Note 1 for
details of unrealized gains or losses included in accumulated
other comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain (loss) on commodity derivatives(1)
|
|
$
|
89,620
|
|
|
$
|
17,202
|
|
|
$
|
209,180
|
|
|
$
|
3,083
|
|
Unrealized (loss) gain on commodity derivatives(1)
|
|
|
(145,048
|
)
|
|
|
40,915
|
|
|
|
(118,879
|
)
|
|
|
15,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (loss) gain on commodity derivatives
|
|
$
|
(55,428
|
)
|
|
$
|
58,117
|
|
|
$
|
90,301
|
|
|
$
|
18,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in (loss) gain on commodity derivatives in the
Consolidated Statements of Operations. |
|
|
7.
|
FAIR
VALUE MEASUREMENTS:
|
As required by the Fair Value Measurements and Disclosure Topic
of the FASB Accounting Standards Codification, we define fair
value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between
market participants at the measurement date and establishes a
three
16
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
level hierarchy for measuring fair value. Fair value
measurements are classified and disclosed in one of the
following categories:
|
|
|
Level 1:
|
|
Quoted prices (unadjusted) in active markets for identical
assets and liabilities that we have the ability to access at the
measurement date.
|
Level 2:
|
|
Inputs other than quoted prices included within Level 1
that are either directly or indirectly observable for the asset
or liability, including quoted prices for similar assets or
liabilities in active markets, quoted prices for identical or
similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or
liability, and inputs that are derived from observable market
data by correlation or other means. Instruments categorized in
Level 2 include non-exchange traded derivatives such as
over-the-counter
forwards and swaps.
|
Level 3:
|
|
Unobservable inputs for the asset or liability, including
situations where there is little, if any, market activity for
the asset or liability.
|
The valuation assumptions utilized to measure the fair value of
the Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level our assets
and liabilities, including both current and non-current
portions, measured at fair value on a recurring basis, as of
September 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
|
|
$
|
|
|
|
$
|
30,292
|
|
|
$
|
|
|
|
$
|
30,292
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
35,746
|
|
|
$
|
|
|
|
$
|
35,746
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
93,718
|
|
|
$
|
|
|
|
$
|
93,718
|
|
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 our
asset retirement obligation, this respective subtopic of FASB
ASC 820 was effective January 1, 2009. Implementation of
this portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity.
Fair
Value of Financial Instruments
The estimated fair value of financial instruments is the amount
at which the instrument could be exchanged currently between
willing parties. The carrying amounts reported in the
consolidated balance sheet for cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value
due to the immediate or short-term maturity of these financial
instruments. We use available market data and valuation
methodologies to estimate the fair value of debt. This
disclosure is presented in accordance with FASB ASC Topic 825,
Financial Instruments, and does not impact our financial
position, results of operations or cash flows.
17
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In April 2009, the FASB updated the requirements for interim
disclosures about fair value of financial instruments requiring
an entity to provide disclosures about fair value of financial
instruments in interim financial information. 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. This
updated requirement for interim disclosures about fair value of
financial instruments 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 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
|
|
|
$
|
104,385
|
|
|
$
|
100,000
|
|
|
$
|
93,836
|
|
5.92% Notes due 2018
|
|
|
200,000
|
|
|
|
210,974
|
|
|
|
200,000
|
|
|
|
180,729
|
|
7.31% Notes due 2016
|
|
|
62,000
|
|
|
|
71,129
|
|
|
|
|
|
|
|
|
|
7.77% Notes due 2019
|
|
|
173,000
|
|
|
|
204,442
|
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
|
195,000
|
|
|
|
195,000
|
|
|
|
270,000
|
|
|
|
270,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
730,000
|
|
|
$
|
785,930
|
|
|
$
|
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.
FASB ASC Topic 855, Subsequent Events (FASB ASC
855), sets forth principles and requirements to be applied
to the accounting for and disclosure of subsequent events. FASB
ASC 855 sets forth the period after the balance sheet date
during which management shall evaluate events or transactions
that may occur for potential recognition or disclosure in the
financial statements, the circumstances under which events or
transactions occurring after the balance sheet date shall be
recognized in the financial statements and the required
disclosures about events or transactions that occurred after the
balance sheet date. These requirements are effective for interim
or annual reporting periods ending after June 15, 2009, and
shall be applied prospectively. Accordingly, the Company adopted
these principles for the quarter ended June 30, 2009. The
Company has evaluated the period subsequent to
September 30, 2009 and through October 30, 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
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ITEM 2
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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 September 30, 2009, the average
price realization for the Companys natural gas was $5.13
per Mcf, including realized gains and losses on commodity
derivatives. The Companys average price realization for
natural gas was $3.09 per Mcf, excluding the realized gains and
losses 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 27% production growth on an Mcfe basis during
the quarter ended September 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 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 throughout the first portion 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). As of
June 29, 2009, service began on the portion of the
REX East pipeline from Audrain County, Missouri to
the Lebanon Hub in Warren County, Ohio with capacity up to
1.8 billion cubic feet of natural gas per day. This section
of REX East includes interconnects
19
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 on schedule and expected to be placed into service during
November 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. From time to time, 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
Financial Accounting Standards Board (FASB)
Accounting Standards Codification (ASC) Topic 815,
Derivatives and Hedging (FASB ASC 815).
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The
Company 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 continues to record the fair value of its commodity
derivatives as an asset or liability on the Consolidated Balance
Sheets, but records the changes in the fair value of its
commodity derivatives in the Consolidated Statements of
Operations as an unrealized gain or loss on commodity
derivatives. There is 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
FASB ASC Topic 820, Fair Value Measurements and Disclosures
(FASB ASC 820), as of January 1, 2008. The
implementation of these requirements 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,
this respective subtopic of FASB ASC 820 was effective
January 1, 2009. Implementation of this portion of the
standard did not have a material impact on consolidated results
of operations, financial position or liquidity. See Note 7
for additional information.
Under FASB ASC 820, fair value is defined as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at measurement date and establishes a three level hierarchy for
measuring fair value. The valuation assumptions utilized to
measure the fair value of the Companys commodity
derivatives were observable inputs based on market data obtained
from independent sources and are considered Level 2 inputs
(quoted prices for similar assets, liabilities (adjusted) and
market-corroborated inputs).
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
20
The fair values summarized below were determined in accordance
with the requirements of FASB ASC 820 and we aligned the
categories below with the Level 1, 2, and 3 fair value
measurements as defined by the Fair Value Measurements and
Disclosures Topic . The balance of net unrealized gains and
losses recognized for our energy-related derivative instruments
at September 30, 2009 is summarized in the following table
based on the inputs used to determine fair value:
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Level 1(a)
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Level 2(b)
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Level 3(c)
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Total
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Assets:
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|
|
|
|
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|
|
|
|
|
|
|
|
|
Current derivative asset
|
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$
|
|
|
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$
|
30,292
|
|
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$
|
|
|
|
$
|
30,292
|
|
Liabilities:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
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$
|
|
|
|
$
|
35,746
|
|
|
$
|
|
|
|
$
|
35,746
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
93,718
|
|
|
$
|
|
|
|
$
|
93,718
|
|
|
|
|
(a) |
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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) |
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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 FASB ASC Topic 718, Compensation Stock
Compensation (FASB ASC 718), which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair
values. Share-based compensation expense recognized for the nine
months ended September 30, 2009 and 2008 was
$7.6 million and $4.9 million, respectively. At
September 30, 2009, there was $5.0 million of total
unrecognized compensation cost related to non-vested share-based
compensation arrangements granted under stock option plans. That
cost is expected to be recognized over a weighted average period
of 0.92 years. See Note 4 for additional information.
FASB ASC 718, requires companies to estimate the fair value of
share-based payment awards on the date of grant using an
option-pricing model. The Company utilized a Black-Scholes
option pricing model to measure the fair value of stock options
granted to employees. The value of the portion of the award that
is ultimately expected to vest is recognized as expense over the
requisite service period in the Companys Consolidated
Statement of Operations. The Companys determination of
fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to, the Companys expected stock price
volatility over the term of the awards and actual and projected
employee stock option exercise behaviors.
Write-down of proved 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 is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly on
21
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 proved 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 SEPTEMBER 30, 2009 VS. QUARTER ENDED
SEPTEMBER 30, 2008
During the quarter ended September 30, 2009, production
increased 27% on a gas equivalent basis to 45.9 Bcfe from
36.3 Bcfe for the same quarter in 2008 attributable to the
Companys successful drilling activities during 2008 and in
the first nine months of 2009. Realized natural gas prices,
including realized gains and losses on commodity derivatives,
decreased 38% to $5.13 per Mcf in the third quarter of 2009 as
compared to $8.21 per Mcf for the same quarter of 2008. During
the three months ended September 30, 2009, the
Companys average price for natural gas was $3.09 per Mcf,
excluding realized gains and losses on commodity derivatives as
compared to $7.71 per Mcf for the same period in 2008. The
decrease in average natural gas prices partially offset by the
increase in production contributed to a 48% decrease in revenues
to $155.2 million as compared to $297.6 million in
2008.
Lease operating expense (LOE) increased to
$9.7 million during the third quarter of 2009 compared to
$8.5 million during the same period in 2008 due primarily
to increased production volumes during the quarter ended
September 30, 2009. On a unit of production basis, LOE
costs decreased to $0.21 per Mcfe at September 30, 2009
compared to $0.23 per Mcfe at September 30, 2008 largely as
a result of increased production volumes and a higher mix of
Ultra operated production during the quarter ended
September 30, 2009.
During the three months ended September 30, 2009,
production taxes were $15.2 million compared to
$31.6 million during the same period in 2008, or $0.33 per
Mcfe compared to $0.87 per Mcfe. The decrease in per unit taxes
is attributable to decreased sales revenues as a result of
decreased realized gas prices during the quarter ended
September 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 $11.4 million for the three
months ended September 30, 2009 compared to
$8.9 million during the same period in 2008 largely due to
increased production volumes. On a per unit basis, gathering
fees increased to $0.25 per Mcfe for the three months ended
September 30, 2009 as compared to $0.24 during the same
period in 2008.
22
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 $16.3 million
for the quarter ended September 30, 2009 as compared to
$11.4 million for the same period in 2008 in association
with REX Pipeline transportation charges. On a per unit basis,
transportation charges increased to $0.35 per Mcfe (on total
company volumes) for the three months ended September 30,
2009 as compared to $0.32 per Mcfe (on total company volumes)
for the same period in 2008 due to increased transportation
rates as a result of further Eastern expansion of REX.
Depletion, depreciation and amortization (DD&A)
expenses increased to $46.4 million during the three months
ended September 30, 2009 from $45.7 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 of
production basis, DD&A decreased to $1.01 per Mcfe for the
quarter ended September 30, 2009 from $1.26 for the quarter
ended September 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. The
write-down reduced earnings in the first quarter of 2009 and
results in lower DD&A expense in future periods.
General and administrative expenses increased to
$5.1 million ($0.11 per Mcfe) for the quarter ended
September 30, 2009 compared to $4.2 million ($0.12 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 $9.7 million during the
quarter ended September 30, 2009 compared to
$5.2 million during the same period in 2008 as a result of
increased borrowings. At September 30, 2009, the Company
had $730.0 million in borrowings outstanding.
During the quarter ended September 30, 2009, the Company
recognized $89.6 million of realized gain on commodity
derivatives and $145.0 million in unrealized loss on
commodity derivatives as compared to $17.2 million of
realized gain on commodity derivatives and $40.9 million in
unrealized gain on commodity derivatives during the quarter
ended September 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
value of these derivative instruments.
The Company recognized a net loss before income taxes of
$13.9 million for the quarter ended September 30, 2009
compared with income of $240.3 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 September 30, 2009 as
compared to the same period in 2008.
The income tax benefit recognized for the quarter ended
September 30, 2009 was $5.6 million compared with an
income tax provision of $91.4 million for the three months
ended September 30, 2008 due to a net loss during the
quarter ended September 30, 2009 primarily as a result of
non-cash, unrealized losses on commodity derivatives.
For the three months ended September 30, 2009, the Company
recognized net loss of $8.3 million or ($0.06) per diluted
share as compared with net income of $149.0 million or
$0.95 per diluted share for the same period in 2008. The
decrease is 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 September 30, 2009 as compared to the same period in
2008.
NINE
MONTHS ENDED SEPTEMBER 30, 2009 VS. NINE MONTHS ENDED
SEPTEMBER 30, 2008
During the nine months ended September 30, 2009, production
increased on a gas equivalent basis to 132.5 Bcfe from
104.6 Bcfe for the same period in 2008 attributable to the
Companys successful drilling activities during 2008 and in
the first nine months of 2009. Realized natural gas prices,
including realized gain and loss on commodity derivatives,
decreased 39% to $4.89 per Mcf during the nine months ended
September 30, 2009 as compared to $7.98 per Mcf for the
same period in 2008. During the nine months ended
23
September 30, 2009, the Companys average price for
natural gas was $3.24 per Mcf, excluding realized gains and
losses on commodity derivatives as compared to $7.95 per Mcf for
the same period in 2008. The decrease in average natural gas
prices partially offset by the increase in production
contributed to a 48% decrease in revenues for the nine months
ended September 30, 2009 to $453.5 million as compared
to $877.0 million in 2008.
LOE increased to $30.1 million during the nine months ended
September 30, 2009 compared to $27.8 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 nine months ended
September 30, 2009. On a unit of production basis, LOE
costs decreased to $0.23 per Mcfe at September 30, 2009
compared to $0.27 per Mcfe at September 30, 2008 as a
result of increased production volumes and a higher mix of Ultra
operated production during the nine months ended
September 30, 2009.
During the nine months ended September 30, 2009, production
taxes were $45.3 million compared to $98.3 million
during the same period in 2008, or $0.34 per Mcfe, compared to
$0.94 per Mcfe. The decrease in per unit taxes is attributable
to decreased sales revenues as a result of lower realized gas
prices during the nine months ended September 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 $33.8 million for the nine
months ended September 30, 2009 compared to
$27.6 million during the same period in 2008 largely due to
increased production volumes. On a per unit basis, gathering
fees decreased to $0.25 per Mcfe for the nine months ended
September 30, 2009 as compared to $0.26 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 $42.8 million
for the period ended September 30, 2009 as compared to
$33.1 million for the same period in 2008 in association
with REX Pipeline transportation charges. On a per unit basis,
transportation charges remained flat at $0.32 per Mcfe (on total
company volumes) for the nine months ended September 30,
2009 and for the same period in 2008.
DD&A increased to $152.0 million during the period
ended September 30, 2009 from $130.7 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 of
production basis, DD&A decreased to $1.15 per Mcfe at
September 30, 2009 from $1.25 at September 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. The write-down reduced earnings in the first
quarter of 2009 and results in lower DD&A expense in future
periods.
General and administrative expenses increased to
$15.4 million ($0.12 per Mcfe) for the period ended
September 30, 2009 compared to $13.0 million ($0.12
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 $26.9 million during the
period ended September 30, 2009 compared to
$15.0 million during the same period in 2008 as a result of
increased borrowings during the period ended September 30,
2009. At September 30, 2009, the Company had
$730.0 million in borrowings outstanding.
Other expense increased to $2.9 million as of
September 30, 2009 primarily as a result of rig termination
payments during the period ended September 30, 2009.
During the nine months ended September 30, 2009, the
Company recognized $209.2 million and $118.9 million
related to realized gain on commodity derivatives and unrealized
loss on commodity derivatives, respectively as compared to
$3.1 million related to realized gain on commodity
derivatives and $15.8 million in unrealized gain on
commodity derivatives during the nine months ended
September 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 value of
these derivative instruments.
24
The Company recognized a loss before income taxes of
$842.5 million for the nine months ended September 30,
2009 compared with income of $551.1 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 realized gains on
commodity derivatives during the nine months ended
September 30, 2009 as compared to the same period in 2008.
The income tax benefit recognized for the nine months ended
September 30, 2009 was $296.0 million compared with an
income tax provision of $201.9 million for the nine months
ended September 30, 2008 due to a net loss during the nine
months ended September 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 nine months ended September 30, 2009, the Company
recognized a net loss of $546.4 million or ($3.61) per
diluted share as compared with net income of $349.2 million
or $2.22 per diluted share for the same period in 2008. The
decrease is 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 realized gains on commodity derivatives
during the nine months ended September 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 nine month period ended September 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 247 wells in
Wyoming and Pennsylvania. For the nine month period ended
September 30, 2009, net capital expenditures were
$537.0 million. At September 30, 2009, the Company
reported a cash position of $13.0 million compared to
$31.0 million at September 30, 2008. Working capital
deficit at September 30, 2009 was $118.4 million
compared to a deficit of $126.7 million at
September 30, 2008. At September 30, 2009, we had
$195.0 million in outstanding borrowings and
$305.0 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 $38.3 million
at September 30, 2009 is comprised of items payable in more
than one year, primarily related to production taxes, the
long-term portion of our incentive compensation plans 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 80% to Wyoming and 20% to Pennsylvania.
Bank indebtedness. The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
25
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 September 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 September 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 September 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 September 30, 2009, we were in compliance with all of
our debt covenants under the 2008 Senior Notes.
Operating Activities. During the nine months
ended September 30, 2009, net cash provided by operating
activities was $420.8 million, a 41% decrease from
$708.2 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 nine months
ended September 30, 2009 as compared to the same period in
2008.
Investing Activities. During the nine months
ended September 30, 2009, net cash used in investing
activities was $586.9 million as compared to
$643.4 million for the same period in 2008. The decrease in
net cash used in investing activities is largely due to
decreased capital expenditures associated with the
Companys drilling activities in 2009 as compared to 2008
partially offset by the timing of payments associated with
capital costs incurred during 2008 and paid during the first
nine months of 2009.
26
Financing Activities. During the nine months
ended September 30, 2009, net cash provided by financing
activities was $165.0 million as compared to net cash used
in investing activities of $44.4 million for the same
period in 2008. The increase in cash provided by net financing
activities is primarily attributable to decreased share
repurchases during the nine months ended September 30, 2009
as compared to 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 September 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
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
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 various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
27
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010. The natural gas reference prices of these
commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties.
From time to time, the Company 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 FASB ASC
815.
Fair Value of Commodity Derivatives: FASB ASC
815 requires that all derivatives be recognized on the balance
sheet as either an asset or liability and be measured at fair
value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At September 30, 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.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
Volume-
|
|
Average
|
|
September 30,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
Mid Continent
|
|
October 2009
|
|
|
130,000
|
|
|
$
|
4.99
|
|
|
$
|
5,908
|
|
Swap
|
|
NW Rockies
|
|
October 2009
|
|
|
130,000
|
|
|
$
|
5.85
|
|
|
$
|
9,987
|
|
Swap
|
|
NW Rockies
|
|
November 2009
|
|
|
50,000
|
|
|
$
|
3.53
|
|
|
$
|
(1,404
|
)
|
Swap
|
|
NW Rockies
|
|
Oct 2009 Dec 2009
|
|
|
100,000
|
|
|
$
|
5.65
|
|
|
$
|
11,661
|
|
Swap
|
|
NW Rockies
|
|
Apr 2010 Oct 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
(4,266
|
)
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
(11,511
|
)
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
(101,165
|
)
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
(8,382
|
)
|
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 nine months ended
September 30, 2009 and 2008 (refer to Note 1 for
details of unrealized gains or losses included in accumulated
other comprehensive income in the Consolidated Balance Sheets):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
Ended September 30,
|
|
Natural Gas Commodity Derivatives:
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Realized gain (loss) on commodity derivatives(1)
|
|
$
|
89,620
|
|
|
$
|
17,202
|
|
|
$
|
209,180
|
|
|
$
|
3,083
|
|
Unrealized (loss) gain on commodity derivatives(1)
|
|
|
(145,048
|
)
|
|
|
40,915
|
|
|
|
(118,879
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)
|
|
|
15,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (loss) gain on commodity derivatives
|
|
$
|
(55,428
|
)
|
|
$
|
58,117
|
|
|
$
|
90,301
|
|
|
$
|
18,848
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in (loss) gain on commodity derivatives in the
Consolidated Statements of Operations. |
28
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
September 30, 2009. There were no changes in our internal
control over financial reporting during the nine months ended
September 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.
ITEM 1A. RISK
FACTORS
There have been no material changes with respect to the risk
factors disclosed in our Annual Report on
Form 10-K
for the fiscal year ended December 31, 2008.
ITEM 2. CHANGES
IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS
IN SENIOR SECURITIES
None.
ITEM 4. SUBMISSION
OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
None.
ITEM 5. OTHER
INFORMATION
None.
29
ITEM 6. EXHIBITS
(a) Exhibits
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the Companys
Quarterly Report on Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on Form 10Q
for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the
Companys Report on Form 10-K/A for the period ended
December 31,2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly Report
on Form 10Q for the period ended June 30, 2001.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
101
|
.DEF**
|
|
XBRL Taxonomy Extension Definition.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
30
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: October 30, 2009
|
|
|
|
By:
|
/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
|
Title:
|
Chief Financial Officer
|
Date: October 30, 2009
31
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. |
32