e10vqza
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q/A
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
June 30, 2008
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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 0-29370
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,
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77060
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Suite 1200, Houston, Texas
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(Zip code)
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(Address of principal executive
offices)
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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 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
(Do not check if a smaller reporting company)
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Smaller reporting company o
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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 July 31, 2008 was
152,833,061.
EXPLANATORY
NOTE
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Ultra Petroleum Corp. (the Company) and the Audit
Committee of the Board of Directors determined that the
contemporaneous formal documentation we had prepared in the
first quarter of 2008 to support our initial natural gas hedge
designations for production sold on the Rockies Express Pipeline
(REX) did not meet the technical requirements to
qualify for hedge accounting treatment in accordance with
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133). In order
to cause the hedge contracts to qualify for hedge accounting
treatment under SFAS No. 133, the Company was required
to predict and document the future relationship between prices
at REX sales points and the sales prices at the Northwest
Pipeline Rockies (the basis of the contracts) at the time the
derivative contracts were entered into. The actual relationship
between the sales prices at the two locations was different than
that predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
The Company has restated the Consolidated Financial Statements
for the periods ended March 31, 2008 and June 30, 2008
to reflect the inability to qualify for hedge accounting
treatment on the REX designated derivative contracts. The effect
of the restatement is to recognize a non-cash, after tax, mark
to market unrealized loss on commodity derivatives of
$18.0 million in the first quarter of 2008 and a non-cash,
after tax, mark to market unrealized gain on commodity
derivatives of $1.6 million in the second quarter of 2008.
Under this accounting treatment, the Company will recognize a
non-cash, after tax, mark to market unrealized gain on commodity
derivatives of $26.6 million in the third quarter of 2008.
There is no effect in any period on overall cash flows, total
assets, total liabilities or total stockholders equity.
Because these contracts were entered into and expire in fiscal
year 2008, there will be no change in full-year 2008 net
income or operating cash flows as a result of the accounting
treatment of the derivative contracts, as restated. The
restatement did not have any impact on any of the financial
covenants under the Companys Senior Credit Facility or
Senior Notes due 2015 and 2018. Details of the restatement are
indicated in Note 1 to the Consolidated Financial
Statements.
3
PART I
FINANCIAL INFORMATION
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ITEM 1
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FINANCIAL
STATEMENTS
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ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF INCOME
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For the Three Months
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For the Six Months
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Ended June 30,
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Ended June 30,
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2008
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2007
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2008
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2007
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Restated
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Restated
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(Unaudited)
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(Amounts in thousands of U.S. dollars,
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except per share data)
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Revenues:
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Natural gas sales
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$
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277,446
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$
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116,421
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$
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526,568
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$
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263,705
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Oil sales
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30,794
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14,451
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52,809
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23,743
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Total operating revenues
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308,240
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130,872
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579,377
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287,448
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Expenses:
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Lease operating expenses
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8,562
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5,573
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19,299
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10,251
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Production taxes
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35,776
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14,694
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66,711
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32,207
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Gathering fees
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8,766
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6,980
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18,764
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13,473
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Transportation charges
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12,013
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21,671
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Depletion and depreciation
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42,780
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32,591
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85,030
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62,221
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General and administrative
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4,449
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3,421
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8,794
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6,639
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Total operating expenses
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112,346
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63,259
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220,269
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124,791
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Operating income
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195,894
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67,613
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359,108
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162,657
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Other income (expense), net:
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Interest expense
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(4,543
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)
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(4,221
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)
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(9,814
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)
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(6,921
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)
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Realized gain (loss) on commodity derivatives
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(14,119
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)
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(14,119
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)
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Unrealized gain (loss) on commodity derivatives
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2,523
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(25,150
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)
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Interest income
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127
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309
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277
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636
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Total other income (expense), net
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(16,012
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)
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(3,912
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)
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(48,806
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)
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(6,285
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Income before income tax provision
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179,882
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63,701
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310,302
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156,372
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Income tax provision
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63,489
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23,949
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110,510
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55,978
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Net income from continuing operations
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116,393
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39,752
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199,792
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100,394
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Income from discontinued operations, net of tax
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482
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9,317
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415
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15,266
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Net income
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116,875
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49,069
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200,207
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115,660
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Retained earnings, beginning of period
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971,152
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691,375
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887,820
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624,784
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Retained earnings, end of period
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$
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1,088,027
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$
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740,444
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$
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1,088,027
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$
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740,444
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Basic Earnings per Share:
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Income per common share from continuing operations
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$
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0.76
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$
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0.26
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$
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1.31
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$
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0.66
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Income per common share from discontinued operations
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$
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0.00
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$
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0.06
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$
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0.00
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$
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0.10
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Net Income per common share
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$
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0.76
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$
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0.32
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$
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1.31
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$
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0.76
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Fully Diluted Earnings per Share:
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Income per common share from continuing operations
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$
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0.74
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$
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0.25
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$
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1.27
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$
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0.63
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Income per common share from discontinued operations
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$
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0.00
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$
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0.06
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$
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0.00
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$
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0.10
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Net Income per common share
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$
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0.74
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$
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0.31
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$
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1.27
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$
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0.73
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Weighted average common shares outstanding basic
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153,061
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152,022
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152,781
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151,975
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Weighted average common shares outstanding fully
diluted
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157,818
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158,992
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157,905
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159,056
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See accompanying notes to consolidated financial statements.
4
ULTRA
PETROLEUM CORP.
CONDENSED
CONSOLIDATED BALANCE SHEETS
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June 30,
|
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December 31,
|
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|
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2008
|
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2007
|
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Restated
|
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(Unaudited)
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(Amounts in thousands of
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U.S. dollars)
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ASSETS
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Current assets
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Cash and cash equivalents
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$
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60,344
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$
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10,632
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Restricted cash
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2,624
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2,590
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Accounts receivable
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177,409
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135,849
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Derivative assets
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5,625
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Inventory
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6,733
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13,333
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Prepaid drilling costs and other current assets
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2,290
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424
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Total current assets
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249,400
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168,453
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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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1,866,026
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1,537,751
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Unproved
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36,622
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36,778
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Property, plant and equipment
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4,846
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4,739
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Deferred financing costs, derivative assets and other
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3,063
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3,861
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Total assets
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$
|
2,159,957
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$
|
1,751,582
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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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$
|
213,998
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$
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140,641
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Derivative liabilities
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|
54,065
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Current taxes payable
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|
|
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10,839
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Capital cost accrual
|
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|
118,084
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|
|
|
88,445
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|
|
|
|
|
|
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Total current liabilities
|
|
|
386,147
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|
|
|
239,925
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Long-term debt
|
|
|
300,000
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|
|
|
290,000
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|
Deferred income tax liability
|
|
|
376,524
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|
|
|
341,406
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|
Other long-term obligations
|
|
|
49,686
|
|
|
|
26,672
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|
Total shareholders equity
|
|
|
1,047,600
|
|
|
|
853,579
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|
|
|
|
|
|
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Total liabilities and shareholders equity
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|
$
|
2,159,957
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|
$
|
1,751,582
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|
|
|
|
|
|
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See accompanying notes to consolidated financial statements.
5
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
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Six Months Ended
|
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|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
Restated
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands of U.S. dollars)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
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Operating activities:
|
|
|
|
|
|
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|
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Net income for the period
|
|
$
|
200,207
|
|
|
$
|
115,660
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
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|
|
Income from discontinued operations, net of tax provision of
$225 and $8,220, respectively
|
|
|
(415
|
)
|
|
|
(15,266
|
)
|
Depletion and depreciation
|
|
|
85,030
|
|
|
|
62,221
|
|
Deferred income taxes
|
|
|
110,704
|
|
|
|
53,308
|
|
Excess tax benefit from stock based compensation
|
|
|
(62,627
|
)
|
|
|
(11,548
|
)
|
Stock compensation
|
|
|
2,755
|
|
|
|
2,736
|
|
Unrealized (gain) loss on commodity derivatives
|
|
|
25,150
|
|
|
|
|
|
Other
|
|
|
189
|
|
|
|
43
|
|
Net changes in non-cash working capital:
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(34
|
)
|
|
|
(1,207
|
)
|
Accounts receivable
|
|
|
(41,560
|
)
|
|
|
(14,654
|
)
|
Prepaid drilling costs and other current and non-current assets
|
|
|
(1,702
|
)
|
|
|
(1,006
|
)
|
Accounts payable and accrued liabilities
|
|
|
71,124
|
|
|
|
42,729
|
|
Other long-term obligations
|
|
|
20,424
|
|
|
|
(1,748
|
)
|
Current taxes payable
|
|
|
(10,839
|
)
|
|
|
(2,150
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities from continuing
operations
|
|
|
398,406
|
|
|
|
229,118
|
|
Net cash provided by operating activities from discontinued
operations
|
|
|
|
|
|
|
9,522
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
398,406
|
|
|
|
238,640
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
Oil and gas property expenditures
|
|
|
(409,089
|
)
|
|
|
(349,828
|
)
|
Investing activities from discontinued operations
|
|
|
|
|
|
|
(10,960
|
)
|
Post-closing adjustments on sale of subsidiary
|
|
|
640
|
|
|
|
|
|
Change in capital cost accrual
|
|
|
29,639
|
|
|
|
(9,752
|
)
|
Inventory
|
|
|
6,600
|
|
|
|
5,837
|
|
Purchase of capital assets
|
|
|
(461
|
)
|
|
|
(219
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(372,671
|
)
|
|
|
(364,922
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
Borrowings on long-term debt
|
|
|
332,000
|
|
|
|
135,000
|
|
Payments on long-term debt
|
|
|
(322,000
|
)
|
|
|
|
|
Deferred financing costs
|
|
|
(1,580
|
)
|
|
|
(1,082
|
)
|
Repurchased shares
|
|
|
(68,635
|
)
|
|
|
(39,744
|
)
|
Excess tax benefit from stock based compensation
|
|
|
62,627
|
|
|
|
11,548
|
|
Stock issued for compensation
|
|
|
4,934
|
|
|
|
|
|
Proceeds from exercise of options
|
|
|
16,631
|
|
|
|
4,867
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
23,977
|
|
|
|
110,589
|
|
Increase (decrease) in cash during the period
|
|
|
49,712
|
|
|
|
(15,693
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
10,632
|
|
|
|
14,574
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
60,344
|
|
|
$
|
(1,119
|
)
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
6
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All dollar amounts in this Quarterly Report on
Form 10-Q/A
are expressed in Thousands of U.S. dollars (except per
share data) unless otherwise noted)
DESCRIPTION
OF THE BUSINESS:
Ultra Petroleum Corp. (the Company) is an
independent oil and gas company engaged in the acquisition,
exploration, development, and production of oil and gas
properties. The Company is incorporated under the laws of the
Yukon Territory, Canada. The Companys principal business
activities are conducted in the Green River Basin of Southwest
Wyoming.
|
|
1.
|
FINANCIAL
STATEMENT RESTATEMENT
|
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Ultra Petroleum Corp. (the Company) and the Audit
Committee of the Board of Directors determined that the
contemporaneous formal documentation we had prepared in the
first quarter of 2008 to support our initial natural gas hedge
designations for production sold on the Rockies Express Pipeline
(REX) did not meet the technical requirements to
qualify for hedge accounting treatment in accordance with
Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133). In order
to cause the hedge contracts to qualify for hedge accounting
treatment under SFAS No. 133, the Company was required
to predict and document the future relationship between prices
at REX sales points and the sales prices at the Northwest
Pipeline Rockies (the basis of the contracts) at the time the
derivative contracts were entered into. The actual relationship
between the sales prices at the two locations was different than
that predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In this Form 10Q/A, the Company is restating the
Consolidated Financial Statements for the three and six months
ended June 30, 2008. Unrealized gains and losses associated
with derivative instruments designated to the Companys
production sold on REX have been reclassified from other
comprehensive income to a separate line item on the Consolidated
Statements of Income as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2008
|
|
|
|
Previously
|
|
|
As
|
|
|
Previously
|
|
|
As
|
|
|
|
Reported
|
|
|
Restated
|
|
|
Reported
|
|
|
Restated
|
|
|
Consolidated Statements of Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
263,327
|
|
|
$
|
277,446
|
|
|
$
|
512,449
|
|
|
$
|
526,568
|
|
Total operating revenues
|
|
$
|
294,121
|
|
|
$
|
308,240
|
|
|
$
|
565,258
|
|
|
$
|
579,377
|
|
Operating income
|
|
$
|
181,775
|
|
|
$
|
195,894
|
|
|
$
|
344,989
|
|
|
$
|
359,108
|
|
Realized gain (loss) on commodity derivatives
|
|
$
|
|
|
|
$
|
(14,119
|
)
|
|
$
|
|
|
|
$
|
(14,119
|
)
|
Unrealized gain (loss) on commodity derivatives
|
|
$
|
|
|
|
$
|
2,523
|
|
|
$
|
|
|
|
$
|
(25,150
|
)
|
Income before income tax provision
|
|
$
|
177,359
|
|
|
$
|
179,882
|
|
|
$
|
335,452
|
|
|
$
|
310,302
|
|
Income tax provision
|
|
$
|
62,603
|
|
|
$
|
63,489
|
|
|
$
|
119,337
|
|
|
$
|
110,510
|
|
Net income from continuing operations
|
|
$
|
114,756
|
|
|
$
|
116,393
|
|
|
$
|
216,115
|
|
|
$
|
199,792
|
|
Net income
|
|
$
|
115,238
|
|
|
$
|
116,875
|
|
|
$
|
216,530
|
|
|
$
|
200,207
|
|
Earnings per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.75
|
|
|
$
|
0.76
|
|
|
$
|
1.41
|
|
|
$
|
1.31
|
|
Fully Diluted
|
|
$
|
0.73
|
|
|
$
|
0.74
|
|
|
$
|
1.37
|
|
|
$
|
1.27
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
|
Previously
|
|
|
As
|
|
|
|
Reported
|
|
|
Restated
|
|
|
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss)
|
|
$
|
(35,743
|
)
|
|
$
|
(19,420
|
)
|
Retained earnings
|
|
$
|
1,104,350
|
|
|
$
|
1,088,027
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months
|
|
|
|
Ended June 30, 2008
|
|
|
|
Previously
|
|
|
As
|
|
|
|
Reported
|
|
|
Restated
|
|
|
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
Cash flows from Operating Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
216,530
|
|
|
$
|
200,207
|
|
Unrealized (gain) loss on commodity derivatives
|
|
$
|
|
|
|
$
|
25,150
|
|
Deferred income taxes
|
|
$
|
119,531
|
|
|
$
|
110,704
|
|
|
|
2.
|
SIGNIFICANT
ACCOUNTING POLICIES:
|
The accompanying financial statements, other than the balance
sheet data as of December 31, 2007, are unaudited and were
prepared from the Companys records. Condensed balance
sheet data as of December 31, 2007 was derived from the
Companys audited financial statements, but does not
include all disclosures required by U.S. generally accepted
accounting principles. The Companys management believes
that these financial statements include all adjustments
necessary for a fair presentation of the Companys
financial position and results of operations. All adjustments
are of a normal and recurring nature unless specifically noted.
The Company prepared these statements on a basis consistent with
the Companys annual audited
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
statements and
Regulation S-X.
Regulation S-X
allows the Company to omit some of the footnote and policy
disclosures required by generally accepted accounting principles
and normally included in annual reports on
Form 10-K.
You should read these interim financial statements together with
the financial statements, summary of significant accounting
policies and notes to the Companys most recent annual
report on
Form 10-K.
(a) Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries UP Energy Corporation, Ultra Resources, Inc.
and
Sino-American
Energy through the date of the sale of the China operations. The
Company presents its financial statements in accordance with
U.S. Generally Accepted Accounting Principles
(GAAP). All inter-company transactions and balances
have been eliminated upon consolidation.
(b) Cash and cash equivalents: We
consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents.
(c) Restricted cash: Restricted cash
represents cash received by the Company from production sold
where the final division of ownership of the production is
unknown or in dispute. Wyoming law requires that these funds be
held in a federally insured bank in Wyoming.
(d) Capital assets other than oil and gas
properties: Capital assets are recorded at cost
and depreciated using the declining-balance method based on a
seven-year useful life.
(e) Oil and natural gas properties: The
Company uses the full cost method of accounting for exploration
and development activities as defined by the Securities and
Exchange Commission (SEC). Separate cost centers are
maintained for each country in which the Company incurs costs.
Under this method of accounting, the costs of unsuccessful, as
well as successful, exploration and development activities are
capitalized as oil and gas properties. This includes any
internal costs that are directly related to exploration and
development activities but does not include any costs related to
production, general corporate overhead or similar activities.
The carrying amount of oil and natural gas properties also
includes estimated asset retirement costs recorded based on the
fair value of the asset retirement obligation when incurred.
Gain or loss on the sale or other disposition of oil and natural
gas properties is not recognized, unless the gain or loss would
significantly alter the relationship between capitalized costs
and proved reserves of oil and natural gas attributable to a
country.
The sum of net capitalized costs and estimated future
development costs of oil and natural gas properties are
amortized using the
units-of-production
method based on the proved reserves as determined by independent
petroleum engineers. Oil and natural gas reserves and production
are converted into equivalent units based on relative energy
content. Asset retirement obligations are included in the base
costs for calculating depletion.
Oil and natural gas properties include costs that are excluded
from capitalized costs being amortized. These amounts represent
investments in unproved properties and major development
projects. The Company excludes these costs until proved reserves
are found or until it is determined that the costs are impaired.
All costs excluded are reviewed, at least quarterly, to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized (the depreciation, depletion and amortization
(DD&A) pool).
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly on a
country-by-country
basis utilizing prices in effect on the last day of the quarter.
SEC
regulation S-X
Rule 4-10 states
that if prices in effect at the end of a quarter are the result
of a temporary decline and prices improve prior to the issuance
of the financial statements, the increased price may be applied
in the computation of the ceiling test. The ceiling limits such
pooled costs to the aggregate of the present value of future net
revenues attributable to proved crude oil and natural gas
reserves discounted at 10% plus the lower of cost or market
value of unproved properties less any associated tax effects. If
such capitalized costs exceed the ceiling, the Company will
record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down will reduce earnings in
the period of
9
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
occurrence and result in lower DD&A expense in future
periods. A write-down may not be reversed in future periods,
even though higher oil and natural gas prices may subsequently
increase the ceiling. The effect of implementing
SFAS No. 143 had no effect on the ceiling test
calculation as the future cash outflows associated with settling
asset retirement obligations are excluded from this calculation.
(f) Inventories: Materials and supplies
inventories are carried at the lower of current market value or
cost. Inventory costs include expenditures and other charges
directly and indirectly incurred in bringing the inventory to
its existing condition and location. The Company uses the
weighted average method of recording its inventory. Selling
expenses and general and administrative expenses are reported as
period costs and excluded from inventory cost. At June 30,
2008, drilling and completion supplies inventory of
$6.7 million primarily includes the cost of pipe and
production equipment that will be utilized during the 2008
drilling program.
(g) Forward natural gas sales
transactions: The Company primarily relies on
fixed price physical delivery contracts, which are considered
sales in the normal course of business, to manage its commodity
price exposure. The Company, from time to time, also uses
derivative instruments as a way to manage its exposure to
commodity prices. (See Note 8).
(h) Income taxes: Income taxes are
accounted for under the asset and liability method. Deferred tax
assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities
and their respective tax basis and operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in
the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. Valuation
allowances are recorded related to deferred tax assets based on
the more likely than not criteria of
SFAS No. 109.
Effective January 1, 2007, we adopted FASB Interpretation
No. 48 (FIN 48) which requires that we
recognize the financial statement benefit of a tax position only
after determining that the relevant tax authority would more
likely than not sustain the position following an audit.
(i) Earnings per share: Basic earnings
per share is computed by dividing net earnings attributable to
common stock by the weighted average number of common shares
outstanding during each period. Diluted earnings per share is
computed by adjusting the average number of common shares
outstanding for the dilutive effect, if any, of common stock
equivalents. The Company uses the treasury stock method to
determine the dilutive effect.
10
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table provides a reconciliation of the components
of basic and diluted net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
Restated
|
|
|
|
|
|
Restated
|
|
|
|
|
|
Net income from continuing operations
|
|
$
|
116,393
|
|
|
$
|
39,752
|
|
|
$
|
199,792
|
|
|
$
|
100,394
|
|
Net income from discontinued operations
|
|
$
|
482
|
|
|
$
|
9,317
|
|
|
$
|
415
|
|
|
$
|
15,266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
116,875
|
|
|
$
|
49,069
|
|
|
$
|
200,207
|
|
|
$
|
115,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
|
|
|
153,061
|
|
|
|
152,022
|
|
|
|
152,781
|
|
|
|
151,975
|
|
Effect of dilutive instruments
|
|
|
4,757
|
|
|
|
6,970
|
|
|
|
5,124
|
|
|
|
7,081
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
|
|
157,818
|
|
|
|
158,992
|
|
|
|
157,905
|
|
|
|
159,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from continuing operations
|
|
$
|
0.76
|
|
|
$
|
0.26
|
|
|
$
|
1.31
|
|
|
$
|
0.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.06
|
|
|
$
|
0.00
|
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
$
|
0.76
|
|
|
$
|
0.32
|
|
|
$
|
1.31
|
|
|
$
|
0.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Earnings per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from continuing operations
|
|
$
|
0.74
|
|
|
$
|
0.25
|
|
|
$
|
1.27
|
|
|
$
|
0.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per common from discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.06
|
|
|
$
|
0.00
|
|
|
$
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share
|
|
$
|
0.74
|
|
|
$
|
0.31
|
|
|
$
|
1.27
|
|
|
$
|
0.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(j) Use of estimates: Preparation of
consolidated financial statements in accordance with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of
the financial statements, and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates.
(k) Accounting for share-based
compensation: The Company applies Statement of
Financial Accounting Standards No. 123 (revised 2004),
Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors
including employee stock options based on estimated fair values.
Share-based compensation expense recognized under
SFAS No. 123R for the six months ended June 30,
2008 and 2007 was $2.8 million and $2.7 million,
respectively. See Note 5 for additional information.
(l) Fair Value Accounting. In September
2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair
Value Measurements (SFAS No. 157).
This Statement defines fair value, establishes a framework for
measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value
measurements. This Statement applies under other accounting
pronouncements that require or permit fair value measurements.
Accordingly, this statement does not require any new fair value
measurements. The changes to current practice resulting from the
application of this statement relate to the definition of fair
value, the methods used to measure fair value, and the expanded
disclosures about fair value measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair value on a recurring basis, primarily our commodity
derivatives, with no material impact on consolidated results of
operations, financial position or liquidity. For those
non-financial assets and liabilities measured or disclosed at
fair value on a non-recurring basis, SFAS No. 157 is
effective January 1, 2009. Implementation of this portion
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of the standard is not expected to have a material impact on
consolidated results of operations, financial position or
liquidity. See Note 10 for additional information.
(m) Revenue Recognition. Natural gas
revenues are recorded based on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Companys net interest. The Company initially
records its entitled share of revenues based on estimated
production volumes. Subsequently, these estimated volumes are
adjusted to reflect actual volumes that are supported by third
party pipeline statements or cash receipts. Since there is a
ready market for natural gas, the Company sells the majority of
its products immediately after production at various locations
at which time title and risk of loss pass to the buyer. Gas
imbalances occur when the Company sells more or less than its
entitled ownership percentage of total gas production. Any
amount received in excess of the Companys share is treated
as a liability. If the Company receives less than its entitled
share, the underproduction is recorded as a receivable.
(n) Other Comprehensive Income: Other
comprehensive income is a term used to define revenues,
expenses, gains and losses that under generally accepted
accounting principles impact Shareholders Equity,
excluding transactions with shareholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
For the Six Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
Restated
|
|
|
|
|
|
Restated
|
|
|
|
|
|
Net income
|
|
$
|
116,875
|
|
|
$
|
49,069
|
|
|
$
|
200,207
|
|
|
$
|
115,660
|
|
Unrealized gain (loss) on derivative instruments*
|
|
|
(7,638
|
)
|
|
|
3,028
|
|
|
|
(37,556
|
)
|
|
|
3,028
|
|
Taxes benefit (expense) on unrealized gain (loss) on derivative
instruments*
|
|
|
2,681
|
|
|
|
(1,063
|
)
|
|
|
13,182
|
|
|
|
(1,063
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income
|
|
$
|
111,918
|
|
|
$
|
51,034
|
|
|
$
|
175,833
|
|
|
$
|
117,625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Relates to derivative instruments that qualify for hedge
accounting treatment under SFAS No. 133. |
At June 30, 2008, the Company recorded a non-current asset
of $1.1 million, a current liability of $54.1 million
and a non-current liability of $2.1 million associated with
the fair value of derivative instruments.
(o) Reclassifications: Certain amounts in
the financial statements of the prior periods have been
reclassified to conform to the current period financial
statement presentation. (Refer to Note 9).
(p) Impact of recently issued accounting
pronouncements: In March 2008, the FASB issued
SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities
(SFAS No. 161). This statement is intended
to improve financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures to increase
transparency about the location and amounts of derivative
instruments in an entitys financial statements; how
derivative instruments and related hedged items are accounted
for under SFAS No. 133; and how derivative instruments
and related hedged items affect financial position, financial
performance, and cash flows. SFAS No. 161 is effective
as of the beginning of an entitys first fiscal year that
begins after November 15, 2008. The Company does not
anticipate that the implementation of SFAS No. 161
will have a material impact on the consolidated results of
operations, financial position or liquidity.
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
3.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
2,281,171
|
|
|
$
|
1,868,564
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(415,145
|
)
|
|
|
(330,813
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,866,026
|
|
|
|
1,537,751
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs
|
|
|
36,622
|
|
|
|
36,778
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,902,648
|
|
|
$
|
1,574,529
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Bank indebtedness
|
|
$
|
|
|
|
$
|
290,000
|
|
Senior notes, due 2015
|
|
|
100,000
|
|
|
|
|
|
Senior notes, due 2018
|
|
|
200,000
|
|
|
|
|
|
Other long-term obligations
|
|
|
49,686
|
|
|
|
26,672
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
349,686
|
|
|
$
|
316,672
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (87.5 basis points
per annum as of June 30, 2008).
At June 30, 2008, we had no outstanding borrowings and
$500.0 million of available borrowing capacity under our
credit facility.
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At June 30, 2008, we were in compliance with all
of our debt covenants under our credit facility.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes
(the Notes) pursuant to a Master Note Purchase
Agreement between the Company and the purchasers of the Notes.
The Notes rank pari passu with the Companys bank credit
facility. Payment of the Notes is guaranteed by Ultra Petroleum
Corp. and UP Energy Corporation. Of the Notes,
$200.0 million are 5.92% Senior Notes due 2018 and
$100.0 million are 5.45% Senior Notes due 2015.
13
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Proceeds from the sale of the Notes were used to repay bank
debt, but did not reduce the borrowings available to us under
the revolving credit facility.
The Notes are pre-payable in whole or in part at any time. The
Notes are subject to representations, warranties, covenants and
events of default customary for a senior note financing. If
payment default occurs, any Note holder may accelerate its
Notes; if a non-payment default occurs, holders of 51% of the
outstanding principal amount of the Notes may accelerate all the
Notes. At June 30, 2008, we were in compliance with all of
our debt covenants under the Notes.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable, a liability associated with imbalanced production, the
long-term portion of costs associated with our compensation
programs and our asset retirement obligations.
|
|
5.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information under SFAS 123R
The following table summarizes share-based compensation expense
under SFAS No. 123R for the six months ended
June 30, 2008 and 2007, respectively, which was allocated
as follows:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Total cost of share-based payment plans
|
|
$
|
4,866
|
|
|
$
|
4,649
|
|
Amounts capitalized in fixed assets
|
|
$
|
2,111
|
|
|
$
|
1,913
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
2,755
|
|
|
$
|
2,736
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
967
|
|
|
$
|
977
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model based on
assumptions noted in the following table. The Companys
employee stock options have various restrictions including
vesting provisions and restrictions on transfers and hedging,
among others, and are often exercised prior to their contractual
maturity. Expected volatilities used in the fair value estimate
are based on historical volatility of the Companys stock.
The Company uses historical data to estimate share option
exercises, expected term and employee departure behavior used in
the Black-Scholes pricing model. Groups of employees (executives
and non-executives) that have similar historical behavior are
considered separately for purposes of determining the expected
term used to estimate fair value. The assumptions utilized
result from differing pre- and post-vesting behaviors among
executive and non-executive groups. The risk-free rate for
periods within the contractual term of the share option is based
on the U.S. Treasury yield curve in effect at the time of
grant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30, 2008
|
|
|
June 30, 2007
|
|
|
|
Non-Executives
|
|
|
Executives
|
|
|
Non-Executives
|
|
|
Executives
|
|
|
Expected volatility
|
|
|
41.22 - 42.47
|
%
|
|
|
42.5
|
%
|
|
|
42.54 - 43.70
|
%
|
|
|
44.40
|
%
|
Expected dividends
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
Expected term (in years)
|
|
|
5.01 - 5.08
|
|
|
|
5.98
|
|
|
|
4.75 - 5.02
|
|
|
|
5.53
|
|
Risk free rate
|
|
|
2.48 - 3.41
|
%
|
|
|
2.98
|
%
|
|
|
4.52 - 5.07
|
%
|
|
|
4.69
|
%
|
Expected forfeiture rate
|
|
|
15.0
|
%
|
|
|
15.0
|
%
|
|
|
14.0
|
%
|
|
|
14.0
|
%
|
14
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the six months ended June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
Number of
|
|
|
Exercise Price
|
|
|
|
Options
|
|
|
(US$)
|
|
|
Balance, December 31, 2007
|
|
|
7,589
|
|
|
$
|
0.25 to $67.73
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
183
|
|
|
$
|
71.72 to $87.59
|
|
Exercised
|
|
|
(2,325
|
)
|
|
$
|
0.25 to $67.73
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2008
|
|
|
5,447
|
|
|
$
|
0.25 to $87.59
|
|
|
|
|
|
|
|
|
|
|
PERFORMANCE
SHARE PLANS:
Long-Term Equity-Based Incentives. In 2005, we
adopted the Long Term Incentive Plan (LTIP) in order
to further align the interests of key employees with
shareholders and give key employees the opportunity to share in
the long-term performance of the Company by achieving specific
corporate financial and operational goals. Participants are
recommended by the CEO and approved by the Compensation
Committee. Selected officers, managers and other key employees
are eligible to participate in the LTIP which has two
components, an LTIP Stock Option Award and an LTIP Common Stock
Award.
Under the LTIP, each year the Compensation Committee establishes
a percentage of base salary for each participant which is
multiplied by the participants base salary to derive an
LTI Value (Long Term Incentive Value). With respect
to LTIP Stock Option Awards, options are awarded equal to one
half of the LTI Value based on the fair value on the date of
grant (using Black-Scholes methodology).
The other half of the LTI Value is the target amount
that may be awarded to the participant as an LTIP Common Stock
Award at the end of a three year performance period. The
Compensation Committee establishes performance measures at the
beginning of each three year overlapping performance period.
Each participant is also assigned threshold and maximum award
levels in the event that performance is below or above target
levels. Awards are expressed as dollar targets and become
payable in common shares at the end of each performance period
based on the Companys overall performance during such
period. A new three year period begins each January.
Participants must be employed by the Company when an award is
distributed in order to receive an award.
For the performance periods January 2006 December
2008 (2006 LTIP), January 2007 December
2009 (2007 LTIP), and January 2008 2010
(2008 LTIP), the Compensation Committee established
the following performance measures: return on equity, reserve
replacement ratio, and production growth.
For the six months ended June 30, 2008, the Company
recognized $0.3 million, $0.4 million and
$0.3 million in pre-tax compensation expense related to the
2006 LTIP, 2007 LTIP and 2008 LTIP, respectively. For the six
months ended June 30, 2007, the Company recognized
$0.3 million and $0.3 million in pre-tax compensation
expense related to the 2006 LTIP and 2007 LTIP, respectively.
The amounts recognized during the first six months of 2008 and
2007 assume that maximum performance objectives are attained. If
the Company ultimately attains maximum performance objectives,
the associated total compensation cost, estimated at
June 30, 2008, for the three year performance periods would
be approximately $2.6 million, $3.3 million and
$3.1 million (before taxes) related to the 2006 LTIP, 2007
LTIP and 2008 LTIP, respectively.
In 2008, the Company established the second performance period
for the Best in Class program for all employees. The first
performance period ended December 31, 2007 with the
resulting payout in the second quarter of 2008. The Best in
Class program recognizes and financially rewards the collective
efforts of all of our employees in achieving sustained industry
leading performance and the enhancement of shareholder value.
15
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Under the Best in Class program, on January 1, 2008 or the
employment date if subsequent to January 1, 2008, all
employees received a contingent award of stock units equal to
$60,000 worth of our common stock based on the average high and
low share price on the date of grant. Employees joining the
Company after January 1, 2008 will participate on a pro
rata basis based on their length of employment during the
performance period. The number of units that will vest and
become payable is based on our performance relative to the
industry during a three-year performance period beginning
January 1, 2008, and ending December 31, 2010, and are
set at threshold (50%), target (100%) and maximum (150%) levels.
For each vested unit, the participant will receive one share of
common stock. The performance measures are all sources finding
and development cost and full cycle economics.
For the six months ended June 30, 2008, the Company
recognized $0.3 million in pre-tax compensation expense
related to the Best in Class program. For the six months ended
June 30, 2007, the Company recognized $0.3 million in
pre-tax compensation expense related to the first performance
period of the Best in Class program. The amount recognized for
the six months ended June 30, 2008 assumes that target
performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total
compensation cost will be approximately $3.0 million before
income taxes.
|
|
6.
|
SHARE
REPURCHASE PROGRAM:
|
On May 17, 2006, the Company announced that its Board of
Directors authorized a share repurchase program for up to an
aggregate $1 billion of the Companys outstanding
common stock which has been and will be funded by cash on hand
and the Companys senior credit facility. Pursuant to this
authorization, the Company has commenced a program to purchase
up to $500.0 million of the Companys outstanding
shares through open market transactions or privately negotiated
transactions. The stock repurchase will be funded with cash held
in an Ultra Resources bank account or the Companys senior
credit facility.
The following tables summarize the Companys share
repurchases in total (open market repurchases plus net share
settlements) as of June 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Weighted Average
|
|
|
|
|
Total
|
|
Purchased
|
|
|
Price per Share
|
|
|
$ Value
|
|
|
1st Quarter 2008
|
|
|
397
|
|
|
$
|
75.25
|
|
|
$
|
29,829
|
|
2nd Quarter 2008
|
|
|
452
|
|
|
$
|
85.97
|
|
|
$
|
38,807
|
|
Prior
|
|
|
5,694
|
|
|
$
|
51.73
|
|
|
$
|
294,549
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008
|
|
|
6,543
|
|
|
$
|
55.52
|
|
|
$
|
363,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Weighted Average
|
|
|
|
|
Open Market
|
|
Purchased
|
|
|
Price per Share
|
|
|
$ Value
|
|
|
1st Quarter 2008
|
|
|
214
|
|
|
$
|
75.53
|
|
|
$
|
16,139
|
|
2nd Quarter 2008
|
|
|
210
|
|
|
$
|
84.13
|
|
|
$
|
17,643
|
|
Prior
|
|
|
5,401
|
|
|
$
|
51.19
|
|
|
$
|
276,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008
|
|
|
5,825
|
|
|
$
|
53.27
|
|
|
$
|
310,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Weighted Average
|
|
|
|
|
Net Share Settlements
|
|
Purchased
|
|
|
Price per Share
|
|
|
$ Value
|
|
|
1st Quarter 2008
|
|
|
183
|
|
|
$
|
74.92
|
|
|
$
|
13,690
|
|
2nd Quarter 2008
|
|
|
242
|
|
|
$
|
87.57
|
|
|
$
|
21,164
|
|
Prior
|
|
|
293
|
|
|
$
|
61.73
|
|
|
$
|
18,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 2006 June 30, 2008
|
|
|
718
|
|
|
$
|
73.79
|
|
|
$
|
52,961
|
|
16
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Subsequent to June 30, 2008 and through July 31, 2008,
the Company has repurchased $67.8 million of its
outstanding common stock in open market repurchases or net share
settlements.
The amount of unrecognized tax benefits did not materially
change as of June 30, 2008. It is expected that the amount
of unrecognized tax benefits may change in the next twelve
months; however, Ultra does not expect the change to have a
significant impact on the results of operations or the financial
position of the Company. Interest expense or penalties
recognized during the six months ended June 30, 2008 were
immaterial.
Ultras effective tax rate is 35.6% for the six months
ended June 30, 2008 and 35.8% for the same period in 2007.
|
|
8.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
The Companys major market risk exposure is in the pricing
applicable to its natural gas and oil production. Realized
pricing is currently driven primarily by the prevailing price
for the Companys Wyoming natural gas production.
Historically, prices received for natural gas production have
been volatile and unpredictable. Pricing volatility is expected
to continue. Realized natural gas prices are derived from the
financial statements which include the effects of hedging and
natural gas balancing.
The Company primarily relies on fixed price forward gas sales to
manage its commodity price exposure. These fixed price forward
gas sales are considered normal sales. The Company, from time to
time, also uses derivative instruments to manage its exposure to
commodity prices. The Company has periodically entered into
fixed price to index price swap agreements in order to mitigate
a portion of its commodity price exposure. The natural gas
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
such publications as Inside FERC Gas Market Report.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Ultra Petroleum Corp. (the Company) and the Audit
Committee of the Board of Directors determined that the
contemporaneous formal documentation we had prepared in the
first quarter of 2008 to support our initial natural gas hedge
designations for production sold on the Rockies Express Pipeline
(REX) did not meet the technical requirements to
qualify for hedge accounting treatment in accordance with
SFAS No. 133. In order to cause the hedge contracts to
qualify for hedge accounting treatment under
SFAS No. 133, the Company was required to predict and
document the future relationship between prices at REX sales
points and the sales prices at the Northwest Pipeline Rockies
(the basis of the contracts) at the time the derivative
contracts were entered into. The actual relationship between the
sales prices at the two locations was different than that
predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133. While such derivatives
17
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
no longer qualify for hedge accounting treatment, the Company
believes that these contracts remain a valuable component of our
commodity price risk management program.
The Company also utilizes fixed price forward physical delivery
contracts at southwest Wyoming delivery points to hedge its
commodity price exposure. The Company had the following fixed
price physical delivery contracts in place on behalf of its
interest and those of other parties at June 30, 2008. (In
November 2007, the Minerals Management Service commenced a
Royalty-in-Kind
program which had the effect of increasing the Companys
average net interest in physical gas sales from 80% to
approximately 91%.)
|
|
|
|
|
|
|
|
|
|
|
Volume-
|
|
|
Average
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
|
Price/MMBTU
|
|
|
Calendar 2008
|
|
|
100,000
|
|
|
$
|
6.83
|
|
Summer 2008 (July October)
|
|
|
20,000
|
|
|
$
|
6.88
|
|
Calendar 2009
|
|
|
10,000
|
|
|
$
|
7.51
|
|
Summer 2009 (April October)
|
|
|
90,000
|
|
|
$
|
7.06
|
|
At June 30, 2008, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price (all prices NWPL Rockies
basis).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume-
|
|
|
Average
|
|
|
Unrealized
|
|
|
|
|
|
|
MMBTU/
|
|
|
Price/
|
|
|
Loss (000s) at
|
|
Type
|
|
Remaining Contract Period
|
|
|
Day
|
|
|
MMBTU
|
|
|
6/30/2008*
|
|
|
Swap
|
|
|
July 2008 Oct 2008
|
|
|
|
190,000
|
|
|
$
|
7.19
|
|
|
$
|
(40,801
|
)
|
Swap
|
|
|
Jan 2009 Dec 2009
|
|
|
|
30,000
|
|
|
$
|
7.35
|
|
|
$
|
(14,273
|
)
|
|
|
|
* |
|
Unrealized losses on commodity derivatives of $25,150 pre-tax
($16,322 after tax) are recorded on the Consolidated Statements
of Income and $29,924 pre-tax ($19,421 after tax) are recorded
on the Consolidated Balance Sheets in accumulated other
comprehensive income. |
For the six months ended June 30, 2008, the Company
realized losses associated with financially settled swaps to
counterparties totaling $24.2 million as its net realized
loss on commodity derivatives. Of this amount,
$14.1 million is recognized as realized loss on commodity
derivatives on the income statement and $10.1 million is
included as a reduction of natural gas sales associated with
cash flow hedges on the income statement.
|
|
9.
|
DISCONTINUED
OPERATIONS:
|
During the third quarter of 2007, we made the decision to
dispose of
Sino-American
Energy Corporation, which owned our Bohai Bay assets in China,
in order to focus on our legacy asset in the Pinedale Field in
southwest Wyoming. The reserve volumes sold represent all of
Ultras international assets and, previously, were the only
results included in our foreign operating segment.
On September 26, 2007, our wholly-owned subsidiary, UP
Energy Corporation, a Nevada corporation, entered into a
definitive share purchase agreement with an effective date of
June 30, 2007 and a closing date of October 22, 2007
in order to sell all of the outstanding shares of
Sino-American
Energy Corporation
(Sino-American),
a Texas corporation, for a total purchase price of
US$223.0 million, subject to adjustments. The Company
recorded results of operations for the China properties through
the close date of October 22, 2007.
18
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has accounted for its
Sino-American
operations as discontinued operations and has reclassified prior
period financial statements to exclude these businesses from
continuing operations. A summary of financial information
related to the Companys discontinued operations is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six
|
|
|
|
For the Three Months
|
|
|
Months
|
|
|
|
Ended June 30,
|
|
|
Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Operating revenues
|
|
$
|
|
|
|
$
|
25,951
|
|
|
$
|
|
|
|
$
|
45,568
|
|
Post closing adjustment on sale of subsidiary
|
|
|
743
|
|
|
|
|
|
|
|
640
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
12,399
|
|
|
|
|
|
|
|
22,082
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax provision
|
|
|
743
|
|
|
|
13,552
|
|
|
|
640
|
|
|
|
23,486
|
|
Income tax provision
|
|
|
261
|
|
|
|
4,235
|
|
|
|
225
|
|
|
|
8,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of tax
|
|
$
|
482
|
|
|
$
|
9,317
|
|
|
$
|
415
|
|
|
$
|
15,266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.
|
FAIR
VALUE MEASUREMENTS:
|
On September 15, 2006, the FASB issued
SFAS No. 157, Fair Value Measurement. We
adopted SFAS No. 157 effective January 1, 2008.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the measurement date and establishes a three level hierarchy
for measuring fair value. The statement requires fair value
measurements be classified and disclosed in one of the following
categories:
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 noncurrent portions,
measured at fair value on a recurring basis, as of June 30,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets:
|
Derivatives
|
|
$
|
|
|
|
$
|
1,071
|
|
|
$
|
|
|
|
$
|
1,071
|
|
|
Liabilities:
|
Derivatives
|
|
$
|
|
|
|
$
|
56,145
|
|
|
$
|
|
|
|
$
|
56,145
|
|
19
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. The derivative transactions are
placed with major financial institutions or with counterparties
of high credit quality that present minimal credit risks to the
Company. Additionally, the Company considers that it is of
substantial credit quality and has the financial resources and
willingness to meet its potential repayment obligations
associated with the derivative transactions.
The Company 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.
20
|
|
ITEM 2
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the consolidated financial statements and related notes of
the Company. Except as otherwise indicated all amounts are
expressed in U.S. Dollars. We operate in one industry
segment, natural gas and oil exploration and development with
one geographical segment; the United States. (See Note 9
for a discussion regarding the sale of our Chinese assets).
The Company currently generates substantially all of its
revenue, earnings and cash from the production and sales of
natural gas and oil from its property in southwest Wyoming. The
price of natural gas in the southwest Wyoming region is a
critical factor to the Companys business. The price of gas
in southwest Wyoming historically has been volatile. The average
realizations for the period
2003-2008
have ranged from $2.33 to $8.64 per Mcf. This volatility could
be detrimental to the Companys financial performance. The
Company seeks to limit the impact of this volatility on its
results by entering into fixed price forward physical delivery
contracts and swap agreements for gas in southwest Wyoming.
During the quarter ended June 30, 2008, the average price
realization for the Companys natural gas was $8.06 per
Mcf, including realized gains and losses on commodity
derivatives. The Companys average price realization for
natural gas was $8.80 per Mcf, excluding realized gains and
losses on commodity derivatives.
The Company has grown its natural gas and oil production
significantly over the past three years and management believes
it has the ability to continue growing production by drilling
already identified locations on its leases in Wyoming. The
Company delivered 23% production growth from continuing
operations on an Mcfe basis during the quarter ended
June 30, 2008 as compared to the same quarter in 2007.
Rockies Express Pipeline. In December 2005,
the Company agreed to become an anchor shipper on the Rockies
Express Pipeline (REX) securing pipeline
infrastructure providing sufficient capacity to transport a
portion of its natural gas production away from southwest
Wyoming and to provide for reasonable basis differentials for
its natural gas in the future. The Companys commitment
involves capacity of 200,000 MMBtu per day of natural gas
for a term of 10 years (beginning in the first quarter of
2008), and the Company is obligated to pay REX certain demand
charges related to its rights to hold this firm transportation
capacity as an anchor shipper. The pipeline will be completed in
two (2) phases: REX-West (Wyoming to Missouri) and REX-East
(Missouri to Ohio).
During the quarter ended June 30, 2008, the REX-West
pipeline was extended from the ANR delivery point in Brown
County, Kansas to the Panhandle Eastern Pipeline system at
Audrain County, Missouri and placed into service. With the
completion of this segment, the Company is able to deliver its
firm capacity of 200,000 MMBtu per day of natural gas from
Wyoming to markets in the mid-west.
On May 30, 2008, the FERC issued a Certificate of Public
Convenience and Necessity for the REX-East project. Kinder
Morgan, the managing member of REX, has indicated that the
current schedule anticipates REX-East to be operational by the
end of 2008 to pipeline interconnections near Lebannon, Ohio.
Kinder Morgan has further advised that, when fully completed,
(estimated to be Mid-Year 2009) the REX-East pipeline will
provide up to 1.8 Bcf per day of natural gas transportation
capacity from the Rockies to Clarington, Ohio.
Discontinued Operations. On September 27,
2007, the Company announced the execution of a stock purchase
agreement for the sale of
Sino-American
Energy Corporation which represents all of Ultras interest
in Bohai Bay, China for $223 million. Despite having owned
Sino-American
in the first half of 2007, under generally accepted accounting
principles (GAAP), its operations have been
reclassified as Discontinued Operations for the
entire quarter. As a result, production, revenues and expenses
associated with
Sino-American
have been removed from continuing operations and reclassified to
discontinued operations. The sale closed on October 22,
2007, with an effective date of June 30, 2007.
Fair Value Measurements. The Company adopted
SFAS No. 157 as of January 1, 2008. The
implementation of SFAS No. 157 was applied
prospectively for our assets and liabilities that are measured
at fair value on a recurring basis, primarily our commodity
derivatives, with no material impact on consolidated results of
operations, financial position or liquidity. See Note 10
for additional information.
21
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at measurement date and establishes a three level hierarchy for
measuring fair value. The valuation assumptions utilized to
measure the fair value of the Companys commodity
derivatives were observable inputs based on market data obtained
from independent sources and are considered Level 2 inputs
(quoted prices for similar assets, liabilities (adjusted) and
market-corroborated inputs). In consideration of counterparty
credit risk, the Company assessed the possibility of whether
each counterparty to the derivative would default by failing to
make any contractually required payments as scheduled in the
derivative instrument in determining the fair value. The
derivative transactions are placed with major financial
institutions or with counter-parties of high credit quality,
which in the Companys opinion, present minimal credit
risks to the Company. Additionally, the Company considers that
it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance
with the requirements of SFAS No. 157. In addition, we
aligned the categories below with the Level 1, 2, and 3
fair value measurements as defined by SFAS No. 157.
The balance of net unrealized gains and losses recognized for
our energy-related derivative instruments at June 30, 2008
is summarized in the following table based on the inputs used to
determine fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1(a)
|
|
Level 2(b)
|
|
Level 3(c)
|
|
Total
|
|
Assets:
|
Derivatives
|
|
$
|
|
|
|
$
|
1,071
|
|
|
$
|
|
|
|
$
|
1,071
|
|
|
Liabilities:
|
Derivatives
|
|
$
|
|
|
|
$
|
56,145
|
|
|
$
|
|
|
|
$
|
56,145
|
|
|
|
|
(a) |
|
Values represent observable unadjusted quoted prices for traded
instruments in active markets. |
|
(b) |
|
Values with inputs that are observable directly or indirectly
for the instrument, but do not qualify for Level 1. |
|
(c) |
|
Values with a significant amount of inputs that are not
observable for the instrument. |
Share-Based Payment Arrangements. The Company
applies Statement of Financial Accounting Standards No. 123
(revised 2004), Share-Based Payment
(SFAS No. 123R) which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair
values. Share-based compensation expense recognized under
SFAS No. 123R for the six months ended June 30,
2008 and 2007 was $2.8 million and $2.7 million,
respectively. At June 30, 2008, there was
$11.2 million of total unrecognized compensation cost
related to non-vested share-based compensation arrangements
granted under stock option plans. That cost is expected to be
recognized over a weighted average period of 1.9 years. See
Note 5 for additional information.
SFAS No. 123R requires companies to estimate the fair
value of share-based payment awards on the date of grant using
an option-pricing model. The Company utilized a Black-Scholes
option pricing model to measure the fair value of stock options
granted to employees. The value of the portion of the award that
is ultimately expected to vest is recognized as expense over the
requisite service periods in the Companys Consolidated
Statement of Operations. The Companys determination of
fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to the Companys expected stock price
volatility over the term of the awards and actual and projected
employee stock option exercise behaviors.
Full Cost Method of Accounting. The Company
uses the full cost method of accounting for oil and gas
operations whereby all costs associated with the exploration for
and development of oil and gas reserves are capitalized on a
country-by-country
basis. Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells and overhead charges directly related to acquisition,
exploration and development activities. Substantially all of the
oil and gas activities are conducted jointly with others and,
accordingly, the amounts reflect only the Companys
22
proportionate interest in such activities. Inflation has not had
a material impact on the Companys results of operations
and is not expected to have a material impact on the
Companys results of operations in the future.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly on a
country-by-country
basis utilizing prices in effect on the last day of the quarter.
SEC
regulation S-X
Rule 4-10 states
that if prices in effect at the end of a quarter are the result
of a temporary decline and prices improve prior to the issuance
of the financial statements, the increased price may be applied
in the computation of the ceiling test. The ceiling limits such
pooled costs to the aggregate of the present value of future net
revenues attributable to proved crude oil and natural gas
reserves discounted at 10% plus the lower of cost or market
value of unproved properties less any associated tax effects. If
such capitalized costs exceed the ceiling, the Company will
record a write-down to the extent of such excess as a non-cash
charge to earnings. Any such write-down will reduce earnings in
the period of occurrence and result in lower DD&A expense
in future periods.
A write-down may not be reversed in future periods, even though
higher oil and natural gas prices may subsequently increase the
ceiling.
RESULTS
OF OPERATIONS
QUARTER
ENDED JUNE 30, 2008 VS. QUARTER ENDED JUNE 30,
2007
During the second quarter of 2008, production from continuing
operations increased 23% on a gas equivalent basis to
34.3 Bcfe from 27.9 Bcfe for the same quarter in 2007
attributable to the Companys successful drilling
activities during 2007 and in the first six months of 2008.
Realized natural gas prices, including the realized gains and
losses on commodity derivatives, increased 84% to $8.06 per Mcf
in the second quarter of 2008 as compared to $4.38 for the
second quarter of 2007. During the three months ended
June 30, 2008, the Companys average price realization
for natural gas was $8.80 per Mcf, excluding realized gains and
losses on commodity derivatives. The increase in realized
average natural gas prices together with the increase in
production contributed to a 125% increase in revenues from
continuing operations, including realized gains and losses on
commodity derivatives, to $294.1 million as compared to
$130.9 million in 2007.
Lease operating expense (LOE) increased to
$8.6 million at June 30, 2008 compared to
$5.6 million at June 30, 2007 due primarily to
increased production volumes. On a unit of production basis, LOE
costs increased to $0.25 per Mcfe at June 30, 2008 compared
to $0.20 per Mcfe at June 30, 2007 mainly due to costs
related to non-operated properties for water disposal expenses.
During the second quarter of 2008, production taxes were
$35.8 million compared to $14.7 million during the
second quarter of 2007, or $1.04 per Mcfe, compared to $0.53 per
Mcfe. The increase in per unit taxes is attributable to
increased sales revenues as a result of increased production and
higher realized gas prices received during the quarter ended
June 30, 2008 as compared to the same period in 2007.
Production taxes are calculated based on a percentage of revenue
from production. Therefore, higher prices received increased
production taxes on a per unit basis.
Gathering fees increased to $8.8 million at June 30,
2008 compared to $7.0 million at June 30, 2007 largely
due to increased production volumes. On a per unit basis,
gathering fees remained relatively flat at $0.26 per Mcfe for
the three months ended June 30, 2008 as compared to $0.25
per Mcfe for the same period in 2007.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred transportation demand charges totaling
$12.0 million for the quarter ended June 30, 2008 in
association with REX Pipeline demand charges.
Depletion, depreciation and amortization (DD&A)
expenses increased to $42.8 million during the quarter
ended June 30, 2008 from $32.6 million for the same
period in 2007, attributable to increased production volumes and
a higher depletion rate, due mainly to increased development
costs. On a unit basis, DD&A increased to $1.25 per Mcfe at
June 30, 2008 from $1.17 at June 30, 2007.
23
General and administrative expenses increased to
$4.4 million ($0.13 per Mcfe) at June 30, 2008
compared to $3.4 million ($0.12 per Mcfe) for the same
period in 2007. The increase in general and administrative
expenses during 2008 is primarily attributable to increased
Medicare taxes as a result of increased employee stock option
exercises during the quarter months ended June 30, 2008.
Interest expense remained relatively flat at $4.5 million
during the quarter ended June 30, 2008 compared to
$4.2 million during the same period in 2007. At
June 30, 2008 and 2007, the Company had $300.0 million
in borrowings outstanding.
During the first quarter of 2008, the Company entered into
derivative contracts to mitigate commodity price exposure on a
portion of the forecasted production (130,000 Mmbtu per day
for April through October 2008) which was expected to be
sold on the Rockies Express Pipeline (REX). REX
became operational during the first quarter of 2008. Due to
limited historical data correlating REX sales points and
NWPL Rockies (the basis of the contracts), the
Company was unable to effectively demonstrate correlation
between the derivative instrument and the forecasted transaction
according to the contemporaneous documentation as set forth
under the requirements of Statement of Financial Accounting
Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities
(SFAS No. 133). As a result, the Company
has restated the related amounts originally classified in
accumulated other comprehensive income on the Consolidated
Balance Sheets to unrealized gain on commodity derivatives on
the Consolidated Statements of Income for these specific
derivative instruments. The effect of this restatement was to
increase income before income taxes by $2.5 million for the
three months ended June 30, 2008. This restatement had no
effect on overall operating cash flow, total assets, total
liabilities or total stockholders equity and there is no
effect on the financial covenants under the Companys
Senior Credit Facility or Senior Notes due 2015 and 2018.
Net income before income taxes increased to $179.9 million
for the quarter ended June 30, 2008 from $63.7 million
for the same period in 2007 primarily as a result of increased
natural gas prices and increased production during the quarter
ended June 30, 2008.
The income tax provision increased to $63.5 million for the
three months ended June 30, 2008 as compared to
$23.9 million for the three months ended June 30, 2007
due to higher pre-tax income.
Income from discontinued operations, net of tax, (which is
comprised entirely of results associated with the Chinese
assets) decreased to $0.5 million for the quarter ended
June 30, 2008 from $9.3 million for the same period in
2007. The sale closed on October 22, 2007. See Note 9
for additional information.
For the quarter ended June 30, 2008, net income increased
to $116.9 million or $0.74 per diluted share as compared
with $49.1 million or $0.31 per diluted share for the same
period in 2007 primarily attributable to increased gas prices
realized in 2008 as well as increased natural gas production.
SIX
MONTHS ENDED JUNE 30, 2008 VS. SIX MONTHS ENDED JUNE 30,
2007
During the six months ended June 30, 2008, production from
continuing operations increased 27% on a gas equivalent basis to
68.4 Bcfe from 53.9 Bcfe for the same period in 2007
attributable to the Companys successful drilling
activities during 2007 and in the first six months of 2008.
Realized natural gas prices, including realized gains and losses
on commodity derivatives, increased 53% to $7.86 per Mcf for the
six months ended June 30, 2008 as compared to $5.13 for the
same period in 2007. During the six months ended June 30,
2008, the Companys average price realization for natural
gas was $8.23 per Mcf, excluding realized gains and losses on
commodity derivatives. The increase in realized average natural
gas prices together with the increase in production contributed
to a 97% increase in revenues from continuing operations,
including realized gains and losses on commodity derivatives, to
$565.3 million as compared to $287.4 million in 2007.
LOE increased to $19.3 million at June 30, 2008
compared to $10.3 million at June 30, 2007 due
primarily to increased production volumes. On a unit of
production basis, LOE costs increased to $0.28 per Mcfe at
June 30, 2008 compared to $0.19 per Mcfe at June 30,
2007 mainly due to costs related to non-operated properties for
water disposal expenses.
24
During the first half of 2008, production taxes were
$66.7 million compared to $32.2 million during the
same period of 2007, or $0.98 per Mcfe, compared to $0.60 per
Mcfe. The increase in per unit taxes is attributable to
increased sales revenues as a result of increased production and
higher realized gas prices received during the six months ended
June 30, 2008 as compared to the same period in 2007.
Production taxes are calculated based on a percentage of revenue
from production. Therefore, higher prices received increased
production taxes on a per unit basis.
Gathering fees increased to $18.8 million at June 30,
2008 compared to $13.5 million at June 30, 2007
largely due to increased production volumes. On a per unit
basis, gathering fees increased to $0.27 per Mcfe for the six
months ended June 30, 2008 as compared to $0.25 per Mcfe
for the same period in 2007.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred transportation demand charges totaling
$21.7 million for the six months ended June 30, 2008
in association with the REX Pipeline demand charges.
DD&A expenses increased to $85.0 million during the
six months ended June 30, 2008 from $62.2 million for
the same period in 2007, attributable to increased production
volumes and a higher depletion rate, due mainly to increased
development costs. On a unit basis, DD&A increased to $1.24
per Mcfe at June 30, 2008 from $1.15 at June 30, 2007.
General and administrative expenses increased to
$8.8 million ($0.13 per Mcfe) at June 30, 2008
compared to $6.6 million ($0.12 per Mcfe) for the same
period in 2007. The increase in general and administrative
expenses during 2008 is primarily attributable to increased
Medicare taxes as a result of increased employee stock option
exercises during the six months ended June 30, 2008.
Interest expense increased to $9.8 million during the six
months ended June 30, 2008 from $6.9 million during
the same period in 2007. The increase is related to higher
average outstanding debt balances during the period ended
June 30, 2008 as compared to the same period in 2007. At
June 30, 2008 and 2007, the Company had $300.0 million
in borrowings outstanding.
During the first quarter of 2008, the Company entered into
derivative contracts to mitigate commodity price exposure on a
portion of the forecasted production (130,000 Mmbtu per day
for April through October 2008) which was expected to be
sold on REX. REX became operational during the first quarter of
2008. Due to limited historical data correlating REX sales
points and NWPL Rockies (the basis of the
contracts), the Company was unable to effectively demonstrate
correlation between the derivative instrument and the forecasted
transaction according to the contemporaneous documentation as
set forth under the requirements of SFAS No. 133. As a
result, the Company has restated the related amounts originally
classified in accumulated other comprehensive income on the
Consolidated Balance Sheets to unrealized loss on commodity
derivatives on the Consolidated Statements of Income for these
specific derivative instruments. The effect of this restatement
was to decrease income before income taxes by $25.2 million
for the six months ended June 30, 2008. This restatement
had no effect on overall operating cash flow, total assets,
total liabilities or total stockholders equity and there
is no effect on the financial covenants under the Companys
Senior Credit Facility or Senior Notes due 2015 and 2018.
Net income before income taxes increased to $310.3 million
for the six months ended June 30, 2008 from
$156.4 million for the same period in 2007 primarily as a
result of increased natural gas prices and increased production
during the six months ended June 30, 2008 and was partially
offset by unrealized losses on commodity derivatives of
$25.2 million during the three months ended June 30,
2008.
The income tax provision increased to $110.5 million for
the six months ended June 30, 2008 as compared to
$56.0 million for the six months ended June 30, 2007
due to higher pre-tax income.
Income from discontinued operations, net of tax, (which is
comprised entirely of results associated with the Chinese
assets) decreased to $0.4 million for the six months ended
June 30, 2008 from $15.3 million for the same period
in 2007. The sale closed on October 22, 2007. See
Note 9 for additional information.
For the six months ended June 30, 2008, net income
increased to $200.2 million or $1.27 per diluted share as
compared with $115.7 million or $0.73 per diluted share for
the same period in 2007 primarily
25
attributable to increased gas prices realized in 2008 as well as
increased natural gas production partially offset by unrealized
losses on commodity derivatives.
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. GAAP. In addition, application of generally
accepted accounting principles requires the use of estimates,
judgments and assumptions that affect the reported amounts of
assets and liabilities as of the date of the financial
statements as well as the revenues and expenses reported during
the period. Changes in these estimates, judgments and
assumptions will occur as a result of future events, and,
accordingly, actual results could differ from amounts estimated.
LIQUIDITY
AND CAPITAL RESOURCES
During the six month period ended June 30, 2008, the
Company relied on cash provided by operations along with
borrowings under the senior credit facility and the issuance of
the Notes to finance its capital expenditures. The Company
participated in the drilling of 190 wells in Wyoming. For
the six month period ended June 30, 2008, net capital
expenditures were $409.1 million. At June 30, 2008,
the Company reported a cash position of $60.3 million
compared to a cash deficit of $1.1 million at June 30,
2007. Working capital at June 30, 2008 was a deficit of
$136.7 million compared to working capital of
$34.1 million at June 30, 2007. As of June 30,
2008, the Company had no bank indebtedness outstanding and
$500.0 million of available borrowing capacity under its
facility. Other long-term obligations of $49.7 million at
June 30, 2008 is comprised of items payable in more than
one year, primarily related to production taxes.
The Companys positive cash provided by operating
activities, along with availability under the senior credit
facility, are projected to be sufficient to fund the
Companys budgeted capital expenditures for 2008, which are
currently projected to be $945.0 million. Of the
$945.0 million budget, the Company plans to allocate
approximately 97% to Wyoming and 3% to Pennsylvania.
Bank indebtedness. The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at our option, based on (A) a rate per annum equal to the
higher of the prime rate or the weighted average fed funds rate
on overnight transactions during the preceding business day plus
50 basis points, or (B) a base Eurodollar rate,
substantially equal to the LIBOR rate, plus a margin based on a
grid of our consolidated leverage ratio (87.5 basis points
per annum as of June 30, 2008).
The facility has restrictive covenants that include the
maintenance of a ratio of consolidated funded debt to EBITDAX
(earnings before interest, taxes, DD&A and exploration
expense) not to exceed
31/2
times; and as long as our debt rating is below investment grade,
the maintenance of an annual ratio of the net present value of
our oil and gas properties to total funded debt of at least 1.75
to 1.00. At June 30, 2008, we were in compliance with all
of our debt covenants under our credit facility.
Senior Notes, due 2015 and 2018: On
March 6, 2008, our wholly-owned subsidiary, Ultra
Resources, Inc. issued $300.0 million Senior Notes pursuant
to a Master Note Purchase Agreement between the Company and the
purchasers of the Notes. The Notes rank pari passu with the
Companys bank credit facility. Payment of the Notes is
guaranteed by Ultra Petroleum Corp. and UP Energy Corporation.
Of the Notes, $200.0 million are 5.92% Senior Notes
due 2018 and $100.0 million are 5.45% Senior Notes due
2015.
Proceeds from the sale of the Notes were used to repay bank
debt, but did not reduce the borrowing available to us under our
revolving credit facility.
26
The Notes are pre-payable in whole or in part at any time. The
Notes are subject to representations, warranties, covenants and
events of default customary for a senior note financing. If
payment default occurs, any Note holder may accelerate its
Notes; if a non-payment default occurs, holders of 51% of the
outstanding principal amount of the Notes may accelerate all the
Notes. At June 30, 2008, we were in compliance with all of
our debt covenants under the Notes.
Operating Activities. During the six months
ended June 30, 2008, net cash provided by operating
activities was $398.4 million, a 67% increase over the
$238.6 million for the same period in 2007. The increase in
net cash provided by operating activities was largely
attributable to the increase in production and realized natural
gas prices during the six months ended June 30, 2008 as
compared to the same period in 2007.
Investing Activities. During the six months
ended June 30, 2008, net cash used in investing activities
was $372.7 million as compared to $364.9 million for
the same period in 2007. The increase in net cash used in
investing activities is largely due to increased capital
expenditures associated with the Companys drilling
activities in 2008.
Financing Activities. During the six months
ended June 30, 2008, net cash provided by financing
activities was $24.0 million as compared to
$110.6 million for the same period in 2007. The decrease in
cash provided by net financing activities is primarily
attributable to decreased net borrowings during the six months
ended June 30, 2008 as compared to the same period in 2007.
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of June 30, 2008.
CAUTIONARY
STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding our financial position,
estimated quantities and net present values of reserves,
business strategy, plans and objectives of the Companys
management for future operations, covenant compliance and those
statements preceded by, followed by or that otherwise include
the words believe, expects,
anticipates, intends,
estimates, projects, target,
goal, plans, objective,
should, or similar expressions or variations on such
expressions are forward-looking statements. The Company can give
no assurances that the assumptions upon which such
forward-looking statements are based will prove to be correct
nor can the Company assure adequate funding will be available to
execute the Companys planned future capital program.
Other risks and uncertainties include, but are not limited to,
fluctuations in the price the Company receives for oil and gas
production, reductions in the quantity of oil and gas sold due
to increased industry-wide demand
and/or
curtailments in production from specific properties due to
mechanical, marketing or other problems, operating and capital
expenditures that are either significantly higher or lower than
anticipated because the actual cost of identified projects
varied from original estimates
and/or from
the number of exploration and development opportunities being
greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates.
See the Companys annual report on
Form 10-K
for the year ended December 31, 2007 for additional risks
related to the Companys business.
ITEM 3 QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Companys major market risk exposure is in the pricing
applicable to its natural gas production. Realized pricing is
currently driven primarily by the prevailing price for the
Companys Wyoming natural gas production. Historically,
prices received for natural gas production have been volatile
and unpredictable. Pricing volatility is expected to continue.
Realized natural gas prices are derived from the financial
statements which include the effects of hedging and natural gas
balancing.
27
The Company primarily relies on fixed price forward gas sales to
manage its commodity price exposure. These fixed price forward
gas sales are considered normal sales. The Company, from time to
time, also uses derivative instruments to manage its exposure to
commodity prices. The Company has periodically entered into
fixed price to index price swap agreements in order to mitigate
a portion of its commodity price exposure. The natural gas
reference prices of these commodity derivative contracts are
typically referenced to natural gas index prices as published by
such publications as Inside FERC Gas Market Report.
Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value. Changes in the
derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For
qualifying cash flow hedges, the unrealized gain or loss on the
derivative is deferred in accumulated other comprehensive income
(loss) to the extent the hedge is effective. Gains and losses on
hedging instruments included in accumulated other comprehensive
income (loss) are reclassified to oil and natural gas sales
revenue in the period that the related production is delivered.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
market value in the Consolidated Balance Sheets, and the
associated unrealized gains and losses are recorded as current
expense or income in the Consolidated Statements of Operations.
On September 15, 2006, the FASB issued
SFAS No. 157, Fair Value Measurement.
SFAS No. 157 defines fair value as the price that
would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at measurement date and establishes a three level hierarchy for
measuring fair value. The valuation assumptions utilized to
measure the fair value of the Companys 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. The
derivative transactions are placed with major financial
institutions or with counterparties of high credit quality that
present minimal credit risks to the Company. Additionally, the
Company considers that it is of substantial credit quality and
has the financial resources and willingness to meet its
potential repayment obligations associated with the derivative
transactions.
The Company also utilizes fixed price forward physical delivery
contracts at southwest Wyoming delivery points to hedge its
commodity price exposure. The Company had the following fixed
price physical delivery contracts in place on behalf of its
interest and those of other parties at June 30, 2008. (In
November 2007, the Minerals Management Service commenced a
Royalty-in-Kind
program which had the effect of increasing the Companys
average net interest in physical gas sales from 80% to
approximately 91%.)
|
|
|
|
|
|
|
|
|
|
|
Volume-
|
|
|
Average
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
|
Price/MMBTU
|
|
|
Calendar 2008
|
|
|
100,000
|
|
|
$
|
6.83
|
|
Summer 2008 (July October)
|
|
|
20,000
|
|
|
$
|
6.88
|
|
Calendar 2009
|
|
|
10,000
|
|
|
$
|
7.51
|
|
Summer 2009 (April October)
|
|
|
90,000
|
|
|
$
|
7.06
|
|
At June 30, 2008, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price (all prices NWPL Rockies
basis).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume-
|
|
Average
|
|
Unrealized
|
|
|
|
|
MMBTU/
|
|
Price/
|
|
Loss (000s) at
|
Type
|
|
Remaining Contract Period
|
|
Day
|
|
MMBTU
|
|
6/30/2008*
|
|
Swap
|
|
|
July 2008 Oct 2008
|
|
|
|
190,000
|
|
|
$
|
7.19
|
|
|
$
|
(40,801
|
)
|
Swap
|
|
|
Jan 2009 Dec 2009
|
|
|
|
30,000
|
|
|
$
|
7.35
|
|
|
$
|
(14,273
|
)
|
|
|
|
* |
|
Unrealized losses on commodity derivatives of $25,150 pre-tax
($16,322 after tax) are recorded on the Consolidated Statements
of Income and $29,924 pre-tax ($19,421 after tax) are recorded
on the Consolidated Balance Sheets in accumulated other
comprehensive income. |
28
On October 31, 2008, in connection with the preparation of
our quarterly report for the third quarter 2008, management of
Ultra Petroleum Corp. (the Company) and the Audit
Committee of the Board of Directors determined that the
contemporaneous formal documentation we had prepared in the
first quarter of 2008 to support our initial natural gas hedge
designations for production sold on the Rockies Express Pipeline
(REX) did not meet the technical requirements to
qualify for hedge accounting treatment in accordance with
SFAS No. 133. In order to cause the hedge contracts to
qualify for hedge accounting treatment under
SFAS No. 133, the Company was required to predict and
document the future relationship between prices at REX sales
points and the sales prices at the Northwest Pipeline Rockies
(the basis of the contracts) at the time the derivative
contracts were entered into. The actual relationship between the
sales prices at the two locations was different than that
predicted by the Company, which affected our ability to
effectively demonstrate ongoing effectiveness between the
derivative instrument and the forecasted transaction as outlined
in our contemporaneous documentation as set forth under the
requirements of SFAS No. 133. While such derivatives
no longer qualify for hedge accounting treatment, the Company
believes that these contracts remain a valuable component of our
commodity price risk management program.
For the six months ended June 30, 2008, the Company
realized losses associated with financially settled swaps to
counterparties totaling $24.2 million as its net realized
loss on commodity derivatives. Of this amount,
$14.1 million is recognized as realized loss on commodity
derivatives on the income statement and $10.1 million is
included as a reduction of natural gas sales associated with
cash flow hedges on the income statement.
ITEM 4
CONTROLS AND PROCEDURES
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
We have performed an evaluation under the supervision and with
the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures, as
defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act). Our disclosure controls and procedures are the
controls and other procedures that we have designed to ensure
that we record, process, accumulate and communicate information
to our management, including our Chief Executive Officer and
Chief Financial Officer, to allow timely decisions regarding
required disclosures and submissions within the time periods
specified in the SECs rules and forms. All internal
control systems, no matter how well designed, have inherent
limitations. Therefore, even those determined to be effective
can provide only a reasonable assurance with respect to
financial statement preparation and presentation. Based on the
evaluation, our management, including our Chief Executive
Officer and Chief Financial Officer, concluded that our
disclosure controls and procedures were effective as of
June 30, 2008. There were no changes in our internal
control over financial reporting during the six months ended
June 30, 2008 that have materially affected or are
reasonably likely to affect, our internal control over financial
reporting.
PART II
OTHER INFORMATION
ITEM 1. LEGAL
PROCEEDINGS
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such
pending or threatened litigation is not likely to have a
material adverse effect on the Companys financial
position, or results of operations.
There have been no material changes with respect to the risk
factors disclosed in our Annual Report on
Form 10-K
for the fiscal year ended December 31, 2007.
29
ITEM 2.
CHANGES IN SECURITIES AND
USE OF PROCEEDS
On May 17, 2006, the Company announced that its Board of
Directors authorized a share repurchase program for up to an
aggregate of $1 billion of the Companys outstanding
common stock which has been and will be funded by cash on hand
and borrowings under the Companys senior credit facility.
Pursuant to this authorization, the Company has commenced a
program to purchase up to $500.0 million of the
Companys outstanding shares through open market
transactions or privately negotiated transactions. (See
Note 6 for further details).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
Maximum Number
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
(or Approximate
|
|
|
|
|
|
|
|
|
|
Purchased
|
|
|
Dollar Value)
|
|
|
|
|
|
|
|
|
|
as Part of
|
|
|
of Shares That
|
|
|
|
|
|
|
|
|
|
Publicly
|
|
|
May Yet be
|
|
|
|
Total Number
|
|
|
Average
|
|
|
Announced
|
|
|
Purchased
|
|
|
|
of Shares
|
|
|
Price Paid
|
|
|
Plans or
|
|
|
Under the
|
|
Period
|
|
Purchased
|
|
|
per Share
|
|
|
Programs
|
|
|
Plans or Programs
|
|
|
Jan 1 Jan 31, 2008
|
|
|
96,321
|
|
|
$
|
71.57
|
|
|
|
96,321
|
|
|
$
|
699 million
|
|
Feb 1 Feb 28, 2008
|
|
|
71,281
|
|
|
$
|
79.04
|
|
|
|
71,281
|
|
|
$
|
693 million
|
|
Mar 1 Mar 31, 2008
|
|
|
228,830
|
|
|
$
|
75.61
|
|
|
|
228,830
|
|
|
$
|
676 million
|
|
Apr 1 Apr 30, 2008
|
|
|
223,559
|
|
|
$
|
79.51
|
|
|
|
223,559
|
|
|
$
|
658 million
|
|
May 1 May 31, 2008
|
|
|
45,668
|
|
|
$
|
90.07
|
|
|
|
45,668
|
|
|
$
|
654 million
|
|
Jun 1 Jun 30, 2008
|
|
|
182,153
|
|
|
$
|
92.88
|
|
|
|
182,153
|
|
|
$
|
637 million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
847,812
|
|
|
$
|
80.96
|
|
|
|
847,812
|
|
|
$
|
637 million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to June 30, 2008 and through July 31, 2008,
the Company has repurchased $67.8 million of its
outstanding common stock in open market repurchases or net share
settlements.
ITEM 3. DEFAULTS
IN SENIOR SECURITIES
None.
ITEM 4. SUBMISSION
OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
The Company held its annual meeting on May 16, 2008. At the
annual meeting, the entire board of directors of the Company was
elected. The votes cast for each of the directors proposed by
the Companys definitive proxy statement on
Schedule 14A was as follows:
|
|
|
|
|
Michael D. Watford
|
|
|
|
134,031,245 voted in favor, zero voted against and 839,676
withheld.
|
W. Charles Helton
|
|
|
|
134,499,794 voted in favor, zero voted against and 371,127
withheld.
|
Stephen J. McDaniel
|
|
|
|
133,826,892 voted in favor, zero voted against and 1,044,029
withheld.
|
Roger A. Brown
|
|
|
|
133,828,182 voted in favor, zero voted against and 1,042,739
withheld.
|
Robert E. Rigney
|
|
|
|
134,542,847 voted in favor, zero voted against and 328,074
withheld.
|
The shareholders of the Company approved the appointment of
Ernst & Young, LLP as the Companys independent
auditors for 2008. There were 134,582,266 votes in favor of
approval of the appointment of Ernst & Young, LLP as
the Companys auditors, zero votes against and 288,654
votes withheld.
The shareholders of the Company voted against the shareholder
proposal regarding climate change with 67,584,431 votes against,
38,958,528 votes in favor of the proposal and 28,327,962 Broker
Non-votes.
A total of 134,870,921 shares were voted by
221 shareholders, representing 88% of the Companys
outstanding shares.
ITEM 5. OTHER
INFORMATION
None.
30
ITEM 6. EXHIBITS AND
REPORTS ON
FORM 8-K -
(a) Exhibits
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
10
|
.1
|
|
Master Note Purchase Agreement dated March 6, 2008
(incorporated by reference to Exhibit 10.1 of the
Companys Report on
Form 8-K
filed on March 6, 2008).
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
ULTRA PETROLEUM CORP.
|
|
|
|
By:
|
/s/ Michael
D. Watford
|
Name: Michael D. Watford
|
|
|
|
Title:
|
Chairman, President and Chief Executive Officer
|
Date: November 4, 2008
|
|
|
|
By:
|
/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
|
Title:
|
Chief Financial Officer
|
Date: November 4, 2008
32
EXHIBIT INDEX
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp (incorporated by
reference to Exhibit 3.2 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001).
|
|
10
|
.1
|
|
Master Note Purchase Agreement dated March 6, 2008
(incorporated by reference to Exhibit 10.1 of the
Companys Report on
Form 8-K
filed on March 6, 2008).
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
33