e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
|
|
|
þ
|
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the quarterly period ended
March 31,
2010
|
or
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the transition period
from
to
|
Commission file number
001-33614
ULTRA PETROLEUM CORP.
(Exact name of registrant as
specified in its charter)
|
|
|
Yukon Territory, Canada
|
|
N/A
|
(State or other jurisdiction
of
incorporation or organization)
|
|
(I.R.S. employer
identification number)
|
363 North Sam Houston Parkway,
Suite 1200, Houston, Texas
(Address of principal
executive offices)
|
|
77060
(Zip
code)
|
(281) 876-0120
(Registrants telephone
number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. YES þ NO o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). YES þ NO o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
|
|
|
|
Large
accelerated
filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Smaller
reporting
company o
|
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). YES o NO þ
The number of common shares, without par value, of Ultra
Petroleum Corp., outstanding as of April 23, 2010 was
152,195,397.
PART I
FINANCIAL INFORMATION
|
|
ITEM 1
|
FINANCIAL
STATEMENTS
|
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands of
|
|
|
|
U.S. dollars, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
250,747
|
|
|
$
|
158,830
|
|
Oil Sales
|
|
|
22,377
|
|
|
|
9,123
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
273,124
|
|
|
|
167,953
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
10,324
|
|
|
|
10,243
|
|
Production taxes
|
|
|
28,407
|
|
|
|
17,351
|
|
Gathering fees
|
|
|
11,955
|
|
|
|
10,791
|
|
Transportation charges
|
|
|
15,905
|
|
|
|
13,355
|
|
Depletion and depreciation
|
|
|
51,267
|
|
|
|
60,661
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
General and administrative
|
|
|
6,402
|
|
|
|
4,574
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
124,260
|
|
|
|
1,153,975
|
|
Operating income (loss)
|
|
|
148,864
|
|
|
|
(986,022
|
)
|
Other income (expense), net:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(11,718
|
)
|
|
|
(7,297
|
)
|
Gain on commodity derivatives
|
|
|
181,351
|
|
|
|
206,428
|
|
Other income (expense) net
|
|
|
151
|
|
|
|
(2,613
|
)
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net
|
|
|
169,784
|
|
|
|
196,518
|
|
Income (loss) before income tax provision (benefit)
|
|
|
318,648
|
|
|
|
(789,504
|
)
|
Income tax provision (benefit)
|
|
|
116,272
|
|
|
|
(276,916
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
202,376
|
|
|
$
|
(512,588
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
1.33
|
|
|
$
|
(3.39
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
1.31
|
|
|
$
|
(3.39
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic
|
|
|
152,073
|
|
|
|
151,238
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding fully
diluted
|
|
|
154,366
|
|
|
|
151,238
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
3
ULTRA
PETROLEUM CORP.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
(Amounts in thousands of
|
|
|
|
U. S. dollars, except share data)
|
|
|
ASSETS
|
Current Assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,017
|
|
|
$
|
14,254
|
|
Restricted cash
|
|
|
1,681
|
|
|
|
1,681
|
|
Oil and gas revenue receivable
|
|
|
89,708
|
|
|
|
82,326
|
|
Joint interest billing and other receivables
|
|
|
40,708
|
|
|
|
29,411
|
|
Derivative assets
|
|
|
93,292
|
|
|
|
4,398
|
|
Deferred tax assets
|
|
|
|
|
|
|
12,225
|
|
Inventory
|
|
|
4,011
|
|
|
|
4,498
|
|
Prepaid drilling costs and other current assets
|
|
|
15,996
|
|
|
|
4,948
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
251,413
|
|
|
|
153,741
|
|
Oil and gas properties, net, using the full cost method of
accounting:
|
|
|
|
|
|
|
|
|
Proved
|
|
|
1,890,801
|
|
|
|
1,794,603
|
|
Unproved properties not being amortized
|
|
|
320,400
|
|
|
|
|
|
Property, plant and equipment
|
|
|
87,919
|
|
|
|
73,435
|
|
Long-term derivative assets
|
|
|
15,889
|
|
|
|
2,554
|
|
Restricted cash
|
|
|
|
|
|
|
28,257
|
|
Deferred financing costs and other
|
|
|
6,366
|
|
|
|
7,415
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,572,788
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
127,930
|
|
|
$
|
131,122
|
|
Production taxes payable
|
|
|
63,751
|
|
|
|
60,820
|
|
Deferred tax liabilities
|
|
|
33,054
|
|
|
|
|
|
Derivative liabilities
|
|
|
1,068
|
|
|
|
35,033
|
|
Capital cost accrual
|
|
|
91,133
|
|
|
|
64,216
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
316,936
|
|
|
|
291,191
|
|
Long-term debt
|
|
|
1,046,000
|
|
|
|
795,000
|
|
Deferred income tax liabilities
|
|
|
297,055
|
|
|
|
239,217
|
|
Long-term derivative liabilities
|
|
|
4,717
|
|
|
|
50,542
|
|
Other long-term obligations
|
|
|
51,644
|
|
|
|
35,858
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Common stock no par value; authorized
unlimited; issued and outstanding 152,195,397 and
151,759,343 at March 31, 2010 and December 31, 2009
respectively
|
|
|
399,283
|
|
|
|
377,339
|
|
Treasury stock
|
|
|
|
|
|
|
(10,525
|
)
|
Retained earnings
|
|
|
457,153
|
|
|
|
281,383
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
856,436
|
|
|
|
648,197
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity
|
|
$
|
2,572,788
|
|
|
$
|
2,060,005
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
4
ULTRA
PETROLEUM CORP.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands
|
|
|
|
of U.S. dollars)
|
|
|
Cash provided by (used in):
|
|
|
|
|
|
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss) for the period
|
|
$
|
202,376
|
|
|
$
|
(512,588
|
)
|
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
51,267
|
|
|
|
60,661
|
|
Write-down of proved oil and gas properties
|
|
|
|
|
|
|
1,037,000
|
|
Deferred income taxes
|
|
|
114,467
|
|
|
|
(276,939
|
)
|
Unrealized gain on commodity derivatives
|
|
|
(182,020
|
)
|
|
|
(186,073
|
)
|
Excess tax benefit from stock based compensation
|
|
|
(11,317
|
)
|
|
|
|
|
Stock compensation
|
|
|
2,781
|
|
|
|
2,125
|
|
Other
|
|
|
84
|
|
|
|
117
|
|
Net changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
|
|
|
|
1,058
|
|
Accounts receivable
|
|
|
(18,679
|
)
|
|
|
29,464
|
|
Prepaid expenses and other
|
|
|
(10,830
|
)
|
|
|
2,006
|
|
Other non-current assets
|
|
|
2,905
|
|
|
|
(2,323
|
)
|
Accounts payable, production taxes and accrued liabilities
|
|
|
3,879
|
|
|
|
(31,966
|
)
|
Other long-term obligations
|
|
|
13,765
|
|
|
|
9,375
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
168,678
|
|
|
|
131,917
|
|
Investing Activities:
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
|
(332,970
|
)
|
|
|
|
|
Oil and gas property expenditures
|
|
|
(198,578
|
)
|
|
|
(220,757
|
)
|
Gathering system expenditures
|
|
|
(15,185
|
)
|
|
|
(1,112
|
)
|
Restricted cash
|
|
|
28,257
|
|
|
|
|
|
Change in capital cost accrual
|
|
|
26,917
|
|
|
|
(58,629
|
)
|
Net proceeds from consolidation of undeveloped land
|
|
|
68,420
|
|
|
|
|
|
Inventory
|
|
|
486
|
|
|
|
(310
|
)
|
Purchase of capital assets
|
|
|
(36
|
)
|
|
|
(591
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(422,689
|
)
|
|
|
(281,399
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
Borrowings on long-term debt
|
|
|
297,000
|
|
|
|
258,000
|
|
Payments on long-term debt
|
|
|
(546,000
|
)
|
|
|
(342,000
|
)
|
Proceeds from issuance of Senior Notes
|
|
|
500,000
|
|
|
|
235,000
|
|
Deferred financing costs
|
|
|
(2,265
|
)
|
|
|
(1,279
|
)
|
Repurchased shares/net share settlements
|
|
|
(16,668
|
)
|
|
|
|
|
Excess tax benefit from stock based compensation
|
|
|
11,317
|
|
|
|
|
|
Proceeds from exercise of options
|
|
|
2,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
245,774
|
|
|
|
149,721
|
|
(Decrease)/increase in cash during the period
|
|
|
(8,237
|
)
|
|
|
239
|
|
Cash and cash equivalents, beginning of period
|
|
|
14,254
|
|
|
|
14,157
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
6,017
|
|
|
$
|
14,396
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
5
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(All amounts in this Quarterly Report on
Form 10-Q
are expressed in thousands of U.S. dollars (except per
share data) unless otherwise noted)
DESCRIPTION
OF THE BUSINESS:
Ultra Petroleum Corp. (the Company) is an
independent oil and gas company engaged in the development,
production, operation, exploration and acquisition of oil and
natural gas properties. The Company is incorporated under the
laws of the Yukon Territory, Canada. The Companys
principal business activities are conducted in the Green River
Basin of Southwest Wyoming and in the north-central Pennsylvania
area of the Appalachian Basin.
|
|
1.
|
SIGNIFICANT
ACCOUNTING POLICIES:
|
The accompanying financial statements, other than the balance
sheet data as of December 31, 2009, are unaudited and were
prepared from the Companys records. Balance sheet data as
of December 31, 2009 was derived from the Companys
audited financial statements, but does not include all
disclosures required by U.S. Generally Accepted Accounting
Principles (GAAP). The Companys management
believes that these financial statements include all adjustments
necessary for a fair presentation of the Companys
financial position and results of operations. All adjustments
are of a normal and recurring nature unless specifically noted.
The Company prepared these statements on a basis consistent with
the Companys annual audited statements and
Regulation S-X.
Regulation S-X
allows the Company to omit some of the footnote and policy
disclosures required by generally accepted accounting principles
and normally included in annual reports on
Form 10-K.
You should read these interim financial statements together with
the financial statements, summary of significant accounting
policies and notes to the Companys most recent annual
report on
Form 10-K.
(a) Basis of presentation and principles of
consolidation: The consolidated financial
statements include the accounts of the Company and its wholly
owned subsidiaries UP Energy Corporation and Ultra Resources,
Inc. The Company presents its financial statements in accordance
with GAAP. All inter-company transactions and balances have been
eliminated upon consolidation.
(b) Cash and cash equivalents: The
Company considers 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.
Long-term restricted cash represents cash that was set aside in
an escrow account in connection with the purchase of additional
acreage in the Marcellus Shale, which closed on
February 22, 2010.
(d) Property, plant and
equipment: Capital assets are recorded at cost
and depreciated using the declining-balance method based on a
seven-year useful life. Gathering system expenditures are
recorded at cost and depreciated using the straight-line method
based on a
30-year
useful life.
(e) Oil and natural gas properties: On
January 6, 2010, the Financial Accounting Standards Board
(FASB) issued an Accounting Standards Update
(ASU), Oil and Gas Reserve Estimation and
Disclosures. The ASU amends FASB Accounting Standards
Codification (ASC) Topic 932, Extractive
Activities Oil and Gas (FASB
ASC 932) to align the reserve calculation and
disclosure requirements of FASB ASC 932 with the
requirements in the SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting Requirements (SEC
Release
No. 33-8995).
The ASU is effective for reporting periods ending on or after
December 31, 2009. Accordingly, the Company adopted the
update to FASB ASC 932 as of December 31, 2009.
6
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company uses the full cost method of accounting for
exploration and development activities as defined by the
Securities and Exchange Commission (SEC). Under this
method of accounting, the costs of unsuccessful, as well as
successful, exploration and development activities are
capitalized as oil and gas properties. This includes any
internal costs that are directly related to exploration and
development activities but does not include any costs related to
production, general corporate overhead or similar activities.
The carrying amount of oil and natural gas properties also
includes estimated asset retirement costs recorded based on the
fair value of the asset retirement obligation when incurred.
Gain or loss on the sale or other disposition of oil and natural
gas properties is not recognized, unless the gain or loss would
significantly alter the relationship between capitalized costs
and proved reserves of oil and natural gas attributable to a
country.
The sum of net capitalized costs and estimated future
development costs of oil and natural gas properties are
amortized using the
units-of-production
method based on the proved reserves as determined by independent
petroleum engineers. Oil and natural gas reserves and production
are converted into equivalent units based on relative energy
content. Asset retirement obligations are included in the base
costs for calculating depletion.
Under the full cost method, costs of unevaluated properties and
major development projects expected to require significant
future costs may be excluded from capitalized costs being
amortized. The Company excludes significant costs until proved
reserves are found or until it is determined that the costs are
impaired. Excluded costs, if any, are reviewed quarterly to
determine if impairment has occurred. The amount of any
impairment is transferred to the capitalized costs being
amortized.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
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.
(f) Inventories: Materials and supplies
inventories are carried at cost. Inventory costs include
expenditures and other charges directly and indirectly incurred
in bringing the inventory to its existing condition and
location. The Company uses the weighted average method of
recording its inventory. Selling expenses and general and
administrative expenses are reported as period costs and
excluded from inventory cost. At March 31, 2010, drilling
and completion supplies inventory of $4.0 million primarily
includes the cost of pipe and production equipment that will be
utilized during the 2010 drilling program.
(g) Derivative Instruments and Hedging
Activities: Currently, the Company largely relies
on derivative instruments to manage its exposure to commodity
price risk. The natural gas reference prices of the
Companys commodity derivative contracts are typically
referenced to natural gas index prices as published by
independent third parties. Additionally, and from time to time,
the Company enters into fixed price to index price swap
agreements in order to mitigate its commodity price exposure on
a portion of its natural gas production. These fixed price
forward gas sales are considered normal sales in the ordinary
course of business and outside the scope of FASB ASC Topic 815,
Derivatives and Hedging (FASB ASC 815). The
Company does not offset the value of its derivative arrangements
with the same counterparty. (See Note 6).
(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
7
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
operating loss and tax credit carryforwards. Deferred tax assets
and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates
is recognized in income in the period that includes the
enactment date. Valuation allowances are recorded related to
deferred tax assets based on the more likely than
not criteria described in FASB ASC Topic 740, Income
Taxes. In addition, we recognize the financial statement benefit
of a tax position only after determining that the relevant tax
authority would more likely than not sustain the position
following an audit.
(i) Earnings per share: Basic earnings
per share is computed by dividing net earnings attributable to
common stockholders by the weighted average number of common
shares outstanding during each period. Diluted earnings per
share is computed by adjusting the average number of common
shares outstanding for the dilutive effect, if any, of common
stock equivalents. The Company uses the treasury stock method to
determine the dilutive effect.
The following table provides a reconciliation of components of
basic and diluted net income (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Net income (loss)
|
|
$
|
202,376
|
|
|
$
|
(512,588
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
|
|
|
152,073
|
|
|
|
151,238
|
|
Effect of dilutive instruments(1)
|
|
|
2,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period
including the effects of dilutive instruments
|
|
|
154,366
|
|
|
|
151,238
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic
|
|
$
|
1.33
|
|
|
$
|
(3.39
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share fully diluted
|
|
$
|
1.31
|
|
|
$
|
(3.39
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Due to the net loss for the three months ended March 31,
2009, 2.6 million shares for options and restricted stock
were anti-dilutive and excluded from the computation of loss per
share. |
(j) Use of estimates: Preparation of
consolidated financial statements in accordance with
U.S. GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
(k) Accounting for share-based
compensation: The Company measures and recognizes
compensation expense for all share-based payment awards made to
employees and directors, including employee stock options, based
on estimated fair values in accordance with FASB ASC Topic 718,
Compensation Stock Compensation.
(l) Fair Value Accounting: The Company
follows FASB ASC Topic 820, Fair Value Measurements and
Disclosures (FASB ASC 820), which defines fair
value, establishes a framework for measuring fair value in
generally accepted accounting principles, and describes
disclosures about fair value measurements. This statement
applies under other accounting topics that require or permit
fair value measurements. For non-financial assets and
liabilities measured or disclosed at fair value on a
non-recurring basis, primarily our asset retirement obligation,
the respective subtopic of FASB ASC 820, was effective
January 1, 2009. Implementation of this portion of the
standard did not have a material impact on consolidated results
of operations, financial position or liquidity. See Note 7
for additional information.
8
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(m) Asset Retirement Obligation: The
initial estimated retirement obligation of properties is
recognized as a liability with an associated increase in oil and
gas properties for the asset retirement cost. Accretion expense
is recognized over the estimated productive life of the related
assets. If the fair value of the estimated asset retirement
obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions
in estimated liabilities can result from revisions of estimated
inflation rates, changes in service and equipment costs and
changes in the estimated timing of settling asset retirement
obligations.
(n) Revenue Recognition: Natural gas
revenues are recorded based on the entitlement method. Under the
entitlement method, revenue is recorded when title passes based
on the Companys net interest. The Company initially
records its entitled share of revenues based on estimated
production volumes. Subsequently, these estimated volumes are
adjusted to reflect actual volumes that are supported by third
party pipeline statements or cash receipts. Since there is a
ready market for natural gas, the Company sells the majority of
its products immediately after production at various locations
at which time title and risk of loss pass to the buyer. Gas
imbalances occur when the Company sells more or less than its
entitled ownership percentage of total gas production. Any
amount received in excess of the Companys share is treated
as a liability. If the Company receives less than its entitled
share, the underproduction is recorded as a receivable.
(o) Other Comprehensive Income
(Loss): Other comprehensive income (loss) is a
term used to define revenues, expenses, gains and losses that
under generally accepted accounting principles impact
Shareholders Equity, excluding transactions with
shareholders.
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Net income (loss)
|
|
$
|
202,376
|
|
|
$
|
(512,588
|
)
|
Reclassification for settlements of derivative instruments*
|
|
|
|
|
|
|
(5,416
|
)
|
Tax expense on settlements of derivative instruments
|
|
|
|
|
|
|
1,901
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
$
|
202,376
|
|
|
$
|
(516,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet (See
Note 6). The net gain or loss in accumulated other
comprehensive income at November 3, 2008 remained on the
balance sheet and the respective months gains or losses
were reclassified from accumulated other comprehensive income to
earnings as the counterparty settlements affected earnings
(January through December 2009). As a result of the
de-designation on November 3, 2008, the Company no longer
has any derivative instruments which qualify for cash flow hedge
accounting. |
(p) Capitalized Interest: Interest is
capitalized on the cost of unevaluated gas and oil properties
that are excluded from amortization and actively being evaluated.
(q) Reclassifications: Certain amounts in
the financial statements of prior periods have been reclassified
to conform to the current period financial statement
presentation.
9
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
2.
|
OIL AND
GAS PROPERTIES:
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Developed Properties:
|
|
|
|
|
|
|
|
|
Acquisition, equipment, exploration, drilling and environmental
costs
|
|
$
|
3,690,725
|
|
|
$
|
3,544,519
|
|
Less: Accumulated depletion, depreciation and amortization(1)
|
|
|
(1,799,924
|
)
|
|
|
(1,749,916
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
1,890,801
|
|
|
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
Unproven Properties:
|
|
|
|
|
|
|
|
|
Acquisition and exploration costs not being amortized(2)(3)
|
|
|
320,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,211,201
|
|
|
$
|
1,794,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During the first quarter of 2009, the Company recorded a
$1.0 billion ($673.0 million net of tax) non-cash
write-down of the carrying value of the Companys proved
oil and gas properties as of March 31, 2009, as a result of
the ceiling test limitations, which is reflected as write-down
of proved oil and gas properties in the accompanying
consolidated statements of operations. The ceiling test was
calculated based on March 31, 2009 wellhead prices of
$2.47 per Mcf for natural gas and $33.91 per barrel for
condensate. |
|
(2) |
|
On February 22, 2010, a wholly-owned subsidiary of the
Company completed its acquisition of oil and gas properties from
NCL Appalachian Partners, L.P. The Company paid
$333.0 million in cash and acquired 78,221 net mineral
acres in the Pennsylvania Marcellus Shale as well as a small
number of producing gas wells. |
|
(3) |
|
Interest is capitalized on the cost of unevaluated oil and
natural gas properties that are excluded from amortization and
actively being evaluated. For the three months ended
March 31, 2010, total interest on outstanding debt was
$13.9 million of which, $2.2 million was capitalized
on the cost of unevaluated oil and natural gas properties. For
the three months ended March 31, 2009, there was no
interest capitalized. |
|
|
3.
|
LONG-TERM
LIABILITIES:
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Bank indebtedness
|
|
$
|
11,000
|
|
|
$
|
260,000
|
|
Senior Notes
|
|
|
1,035,000
|
|
|
|
535,000
|
|
Other long-term obligations
|
|
|
51,644
|
|
|
|
35,858
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,097,644
|
|
|
$
|
830,858
|
|
|
|
|
|
|
|
|
|
|
Bank indebtedness: The Company (through its
subsidiary) is a party to a revolving credit facility with a
syndicate of banks led by JP Morgan Chase Bank, N.A. which
matures in April 2012. This agreement provides an initial loan
commitment of $500.0 million and may be increased to a
maximum aggregate amount of $750.0 million at the request
of the Company. Each bank has the right, but not the obligation,
to increase the amount of its commitment as requested by the
Company. In the event the existing banks increase their
commitment to an amount less than the requested commitment
amount, then it would be necessary to add new financial
institutions to the credit facility.
Loans under the credit facility are unsecured and bear interest,
at the Companys option, based on (A) a rate per annum
equal to the higher of the prime rate or the weighted average
fed funds rate on overnight transactions during the preceding
business day plus 50 basis points, or (B) a base
Eurodollar rate, substantially equal to the LIBOR rate, plus a
margin based on a grid of our consolidated leverage ratio
(100.0 basis points per annum as of March 31, 2010).
10
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At March 31, 2010, the Company had $11.0 million in
outstanding borrowings and $489.0 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 March 31, 2010, the Company was in compliance
with all of our debt covenants under our credit facility.
Senior Notes: On March 6, 2008, the
Companys wholly-owned subsidiary, Ultra Resources, Inc.
issued $300.0 million Senior Notes (the 2008 Senior
Notes) pursuant to a Master Note Purchase Agreement
between the Company and the purchasers of the Notes. On
March 5, 2009, Ultra Resources, Inc., issued
$235.0 million Senior Notes (the 2009 Senior
Notes) pursuant to a First Supplement to the Master Note
Purchase Agreement. And, on January 28, 2010, Ultra
Resources, Inc., agreed to issue an aggregate amount of
$500.0 million of Senior Notes (the 2010 Senior
Notes) pursuant to a Second Supplement to the Master Note
Purchase Agreement. Of the 2010 Senior Notes,
$270.0 million were issued on January 28, 2010 and
$230.0 million were issued on February 16, 2010.
The Senior Notes rank pari passu with the Companys bank
credit facility. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation.
Proceeds from the sale of the 2010 Senior Notes were used to
repay revolving credit facility debt, but did not reduce the
borrowings available to the Company under the revolving credit
facility, and for general corporate purposes, including funding
the Pennsylvania Marcellus Shale acquisition that closed on
February 22, 2010. The Senior Notes are pre-payable in
whole or in part at any time and are subject to representations,
warranties, covenants and events of default customary for a
senior note financing. At March 31, 2010, the Company was
in compliance with all of its debt covenants under the Master
Note Purchase Agreement.
Other long-term obligations: These costs
primarily relate to the long-term portion of production taxes
payable and our asset retirement obligations.
|
|
4.
|
SHARE
BASED COMPENSATION:
|
Valuation
and Expense Information
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
|
Ended March 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Total cost of share-based payment plans
|
|
$
|
4,686
|
|
|
$
|
3,742
|
|
Amounts capitalized in fixed assets
|
|
$
|
1,905
|
|
|
$
|
1,617
|
|
Amounts charged against income, before income tax benefit
|
|
$
|
2,781
|
|
|
$
|
2,125
|
|
Amount of related income tax benefit recognized in income
|
|
$
|
987
|
|
|
$
|
745
|
|
The fair value of each share option award is estimated on the
date of grant using a Black-Scholes pricing model. The
Companys employee stock options have various restrictions
including vesting provisions and restrictions on transfers and
hedging, among others, and are often exercised prior to their
contractual maturity. Expected volatilities used in the fair
value estimates are based on historical volatility of the
Companys stock. The Company uses historical data to
estimate share option exercises, expected term and employee
departure behavior used in the Black-Scholes pricing model.
Groups of employees (executives and non-executives) that have
similar historical behavior are considered separately for
purposes of determining the expected term used to estimate fair
value. The assumptions utilized result from differing pre- and
post-vesting behaviors among executive and non-executive groups.
The risk-free rate for periods within the contractual term of
the share
11
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
option is based on the U.S. Treasury yield curve in effect
at the time of grant. There were no stock options granted during
the three months ended March 31, 2010.
Changes
in Stock Options and Stock Options Outstanding
The following table summarizes the changes in stock options for
the three months ended March 31, 2010 and the year ended
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Number of
|
|
|
Average
|
|
|
|
Options
|
|
|
Exercise Price
|
|
|
|
(000s)
|
|
|
(US$)
|
|
|
Balance, December 31, 2008
|
|
|
4,213
|
|
|
$
|
0.25 to $98.87
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(43
|
)
|
|
$
|
51.60 to $78.55
|
|
Exercised
|
|
|
(666
|
)
|
|
$
|
0.25 to $33.57
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
3,504
|
|
|
$
|
1.49 to $98.87
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(1
|
)
|
|
$
|
75.18
|
|
Exercised
|
|
|
(683
|
)
|
|
$
|
1.49 to $33.57
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2010
|
|
|
2,820
|
|
|
$
|
2.61 to $98.87
|
|
|
|
|
|
|
|
|
|
|
PERFORMANCE
SHARE PLANS:
Long Term Incentive Plans. Each year since
2005, the Company has adopted a Long Term Incentive Plan
(LTIP) in order to further align the interests of
key employees with shareholders and to give key employees the
opportunity to share in the long-term performance of the Company
when specific corporate financial and operational goals are
achieved. Each LTIP covers a performance period of three years.
The 2008 LTIP has two components: an LTIP Stock Option
Award and an LTIP Common Stock Award. In 2009
and 2010, the Compensation Committee (the Committee)
approved an award consisting only of performance-based
restricted stock units to be awarded to each participant.
Under each LTIP, the Compensation Committee establishes a
percentage of base salary for each participant which is
multiplied by the participants base salary to derive a
Long Term Incentive Value. The LTIP Common Stock Award in 2008
and the 2009 and 2010 LTIP award of restricted stock units are
performance-based and are measured over a three year performance
period. For each LTIP award, the Compensation Committee
establishes performance measures at the beginning of each
performance period, and each participant is assigned threshold
and maximum award levels in the event that actual performance is
below or above target levels. For the 2008, 2009 and 2010 LTIP
awards, the Committee established the following performance
measures: return on equity, reserve replacement ratio, and
production growth.
For the three months ended March 31, 2010, the Company
recognized $1.8 million in pre-tax compensation expense
related to the 2008 LTIP Common Stock Award and 2009 and 2010
LTIP award of restricted stock units. For the three months ended
March 31, 2009, the Company recognized $1.6 million in
pre-tax compensation expense related to the 2007 and 2008 LTIP
Common Stock Awards and the 2009 LTIP award of restricted stock
units. The amounts recognized during the three months ended
March 31, 2010 assumes that maximum performance objectives
are attained. If the Company ultimately attains these
performance objectives, the associated total compensation,
estimated at March 31, 2010, for each of the three year
performance periods is expected to be approximately
$4.1 million, $10.6 million, and $10.1 million
related to the 2008 LTIP Common Stock Award and 2009 and 2010
LTIP award of restricted stock units, respectively. Additional
awards of restricted stock units were granted to eligible
employees during 2009 with estimated total compensation of
$10.5 million over the three year performance period
assuming that maximum performance
12
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
objectives are attained. The 2007 LTIP Common Stock Award was
paid in shares of the Companys stock to employees during
the first quarter of 2010 and totaled $4.1 million.
Best in Class Program. In May 2008, the
Company established the 2008 Best in Class Program for all
permanent, full-time employees. Under the 2008 Best in
Class Program, participants are eligible to receive a
number of shares of the Companys common stock based on the
performance of the Company. As with the LTIP, the 2008 Best in
Class Program is measured over a three year performance
period. The 2008 Best in Class Program recognizes and
financially rewards the collective efforts of all of the
Companys employees in achieving sustained industry leading
performance and the enhancement of shareholder value. Under the
2008 Best in Class Program, on January 1, 2008 or the
employment date if subsequent to January 1, 2008, eligible
employees received a contingent award of stock units equal to
$60,000 worth of the Companys common stock based on the
average high and low share price on the first day of the
performance period. Employees joining the Company after
January 1, 2008 participate on a pro-rata basis based on
their length of employment during the performance period.
The number of contingent units that will become payable and vest
upon distribution is based on the Companys performance
relative to the industry during a three year performance period
beginning January 1, 2008, and ending December 31,
2010, and are set at threshold (50%), target (100%), and maximum
(150%) levels. For each vested unit, the participant will
receive one share of common stock. The participant must be
employed on the date the awards are distributed in order to
receive the award.
For the three months ended March 31, 2010, the Company
recognized $0.3 million in pre-tax compensation expense
related to the 2008 Best in Class Program. For the three
months ended March 31, 2009 the Company recognized
$0.2 million in pre-tax compensation expense related to the
2008 Best in Class Program. The amount recognized for the
three months ended March 31, 2010 assumes that target
performance levels are achieved. If the Company ultimately
attains the target performance level, the associated total
compensation related to the 2008 Best in Class Program is
estimated at $4.5 million as of March 31, 2010.
During the quarter ended March 31, 2010, the Company
recorded an income tax provision of $116.3 million or 36.5%
of income before income tax provision. This compares to an
income tax benefit of $276.9 million or 35.1% of the loss
before income tax benefit for the quarter ended March 31,
2009. The effective tax rate increased over the prior period
primarily due to elevated activity levels in the higher state
tax rate jurisdiction of Pennsylvania which increased the
overall effective tax rate to 35.5%. A one-time
catch-up was
required which caused the effective tax rate for the quarter
ended March 31, 2010 to increase to 36.5%.
|
|
6.
|
DERIVATIVE
FINANCIAL INSTRUMENTS:
|
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
Wyoming natural gas production. Historically, prices received
for natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was
13
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effective upon entering into these transactions in March 2009,
with upcoming settlements for production months through December
2010. The natural gas reference prices of these commodity
derivative contracts are typically referenced to natural gas
index prices as published by independent third parties.
From time to time, the Company also utilizes fixed price forward
gas sales to manage its commodity price exposure. These fixed
price forward gas sales are considered normal sales in the
ordinary course of business and outside the scope of FASB
ASC 815, Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At March 31, 2010, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price. See Note 7 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value -
|
|
|
|
|
|
|
Volume -
|
|
Average
|
|
March 31,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
14,097
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
44,741
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
10,000
|
|
|
$
|
6.27
|
|
|
$
|
4,535
|
|
Swap
|
|
NW Rockies
|
|
Apr 2010 Oct 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
13,696
|
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
26,327
|
|
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the three months ended
March 31, 2010 and 2009 (refer to Note 1 for details
of unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
Natural Gas Commodity Derivatives:
|
|
2010
|
|
|
2009
|
|
|
Realized (loss) gain on commodity derivatives(1)
|
|
$
|
(669
|
)
|
|
$
|
20,355
|
|
Unrealized gain on commodity derivatives(1)
|
|
|
182,020
|
|
|
|
186,073
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
181,351
|
|
|
$
|
206,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Operations. |
|
|
7.
|
FAIR
VALUE MEASUREMENTS:
|
As required by the Fair Value Measurements and Disclosure Topic
of the FASB Accounting Standards Codification, we define fair
value as the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between
market participants at the measurement date and establishes a
three
14
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
level hierarchy for measuring fair value. Fair value
measurements are classified and disclosed in one of the
following categories:
|
|
|
Level 1:
|
|
Quoted prices (unadjusted) in active markets for identical
assets and liabilities that we have the ability to access at the
measurement date.
|
Level 2:
|
|
Inputs other than quoted prices included within Level 1
that are either directly or indirectly observable for the asset
or liability, including quoted prices for similar assets or
liabilities in active markets, quoted prices for identical or
similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or
liability, and inputs that are derived from observable market
data by correlation or other means. Instruments categorized in
Level 2 include non-exchange traded derivatives such as
over-the-counter
forwards and swaps.
|
Level 3:
|
|
Unobservable inputs for the asset or liability, including
situations where there is little, if any, market activity for
the asset or liability.
|
The valuation assumptions utilized to measure the fair value of
the Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar assets,
liabilities (adjusted) and market-corroborated inputs).
The following table presents for each hierarchy level our assets
and liabilities, including both current and non-current
portions, measured at fair value on a recurring basis, as of
March 31, 2010. The company has no derivative instruments
which qualify for cash flow hedge accounting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
93,292
|
|
|
$
|
|
|
|
$
|
93,292
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
15,889
|
|
|
$
|
|
|
|
$
|
15,889
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
1,068
|
|
|
$
|
|
|
|
$
|
1,068
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
4,717
|
|
|
$
|
|
|
|
$
|
4,717
|
|
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
For non-financial assets and liabilities measured or disclosed
at fair value on a non-recurring basis, primarily our asset
retirement obligation, this respective subtopic of FASB ASC 820
was effective January 1, 2009. Implementation of this
portion of the standard did not have a material impact on
consolidated results of operations, financial position or
liquidity.
Fair
Value of Financial Instruments
The estimated fair value of financial instruments is the amount
at which the instrument could be exchanged currently between
willing parties. The carrying amounts reported in the
consolidated balance sheet for cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value
due to the immediate or short-term maturity of these financial
instruments. We use available market data and valuation
methodologies to estimate the fair value of debt. This
disclosure is presented in accordance with FASB ASC Topic 825,
Financial Instruments, and does not impact our financial
position, results of operations or cash flows.
15
ULTRA
PETROLEUM CORP.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In April 2009, the FASB updated the requirements for interim
disclosures about fair value of financial instruments requiring
an entity to provide disclosures about fair value of financial
instruments in interim financial information. The Company is
required to include disclosures about the fair value of its
financial instruments whenever it issues financial information
for interim reporting periods. In addition, the Company is
required to disclose in the body or in the accompanying notes of
its summarized financial information for interim reporting
periods and in its financial statements for annual reporting
periods, the fair value of all financial instruments for which
it is practicable to estimate that value, whether recognized or
not recognized in the statement of financial position. This
updated requirement for interim disclosures about fair value of
financial instruments is effective for periods ending after
June 15, 2009 and its adoption had no impact on the
Companys results of operations and financial condition but
requires additional disclosures about the fair value of
financial instruments in the financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010
|
|
|
December 31, 2009
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.45% Notes due 2015
|
|
$
|
100,000
|
|
|
$
|
108,000
|
|
|
$
|
100,000
|
|
|
$
|
108,128
|
|
5.92% Notes due 2018
|
|
|
200,000
|
|
|
|
213,246
|
|
|
|
200,000
|
|
|
|
212,946
|
|
7.31% Notes due 2016
|
|
|
62,000
|
|
|
|
72,313
|
|
|
|
62,000
|
|
|
|
72,684
|
|
7.77% Notes due 2019
|
|
|
173,000
|
|
|
|
211,906
|
|
|
|
173,000
|
|
|
|
205,609
|
|
4.98% Notes due 2017
|
|
|
116,000
|
|
|
|
118,474
|
|
|
|
|
|
|
|
|
|
5.50% Notes due 2020
|
|
|
207,000
|
|
|
|
207,725
|
|
|
|
|
|
|
|
|
|
5.60% Notes due 2022
|
|
|
87,000
|
|
|
|
85,502
|
|
|
|
|
|
|
|
|
|
5.85% Notes due 2025
|
|
|
90,000
|
|
|
|
85,666
|
|
|
|
|
|
|
|
|
|
Credit Facility
|
|
|
11,000
|
|
|
|
11,000
|
|
|
|
260,000
|
|
|
|
260,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,046,000
|
|
|
$
|
1,113,832
|
|
|
$
|
795,000
|
|
|
$
|
859,367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such
pending or threatened litigation is not likely to have a
material adverse effect on the Companys financial position
or results of operations.
FASB ASC Topic 855, Subsequent Events (FASB
ASC 855), sets forth principles and requirements to
be applied to the accounting for and disclosure of subsequent
events. FASB ASC 855 sets forth the period after the
balance sheet date during which management shall evaluate events
or transactions that may occur for potential recognition or
disclosure in the financial statements, the circumstances under
which events or transactions occurring after the balance sheet
date shall be recognized in the financial statements and the
required disclosures about events or transactions that occurred
after the balance sheet date. The FASB issued ASU No
2010-09,
Subsequent Events - Amendments to Certain Recognition and
Disclosure Requirements, on February 24, 2010, in an effort
to remove some contradictions between the requirements of
U.S. GAAP and the SECs filing rules. The amendments
remove the requirement that public companies disclose the date
of their financial statements in both issued and revised
financial statements. The Company has evaluated the period
subsequent to March 31, 2010 for events that did not exist
at the balance sheet date but arose after that date and
determined that no subsequent events arose that should be
disclosed in order to keep the financial statements from being
misleading.
16
|
|
ITEM 2
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
The following discussion of the financial condition and
operating results of the Company should be read in conjunction
with the consolidated financial statements and related notes of
the Company. Except as otherwise indicated, all amounts are
expressed in U.S. dollars. We operate in one industry
segment, natural gas and oil exploration and development with
one geographical segment, the United States.
The Company currently generates substantially all of its
revenue, earnings and cash flow from the production and sales of
natural gas and oil from its property in southwest Wyoming. The
price of natural gas is a critical factor to the Companys
business and the price of natural gas has historically been
volatile. Volatility could be detrimental to the Companys
financial performance. The Company seeks to limit the impact of
this volatility on its results by entering into fixed price
forward physical delivery contracts and swap agreements for
natural gas. During the quarter ended March 31, 2010, the
average price realization for the Companys natural gas was
$5.37 per Mcf, including realized gains and losses on commodity
derivatives. The Companys average price realization for
natural gas was $5.38 per Mcf, excluding the realized gains and
losses on commodity derivatives. (See Note 6).
The Company has grown its natural gas and oil production
significantly over the past five years and management believes
it has the ability to continue growing production by drilling
already identified locations on its leases in Wyoming and
Pennsylvania. The Company delivered 15% production growth on an
Mcfe basis during the quarter ended March 31, 2010 as
compared to the same quarter in 2009.
The Company currently conducts operations exclusively in the
United States. Substantially all of the oil and natural gas
activities are conducted jointly with others and, accordingly,
amounts presented reflect only the Companys proportionate
interest in such activities. Inflation has not had a material
impact on the Companys results of operations and is not
expected to have a material impact on the Companys results
of operations in the future.
Outlook. In 2008 and 2009, we saw significant
changes in the business environment in which we operate,
including severe economic uncertainty, increasing market
volatility and continued tightening of credit markets. These
market conditions contributed to record high commodity prices
during the first half of 2008 and nearly unprecedented drops in
these commodity prices in the second half of 2008 and throughout
2009.
In 2009, the Company established new production records while
maintaining a low cost structure which contributes to the
consistency of the Companys growth and returns. Although
our net cash provided by operating activities was negatively
affected by general economic conditions, we believe that we will
continue to generate positive cash flow from operations, which,
along with our available cash, will provide sufficient liquidity
to allow us to return value to our shareholders.
While we continue to monitor the overall health of the credit
markets, we expect to rely on our available cash, our existing
credit facility and the cash we generate from our operations to
meet our obligations and to fund our capital investments and
operations over the next twelve months. A renewed, long-term
disruption in the credit markets could make financing more
expensive or unavailable, which could have a material adverse
effect on our operations.
Derivative Instruments and Hedging
Activities. Currently, the Company largely relies
on derivative instruments to manage its exposure to commodity
price risk. The natural gas reference prices of the
Companys commodity derivative contracts are typically
referenced to natural gas index prices as published by
independent third parties. Additionally, and from time to time,
the Company enters into fixed price to index price swap
agreements in order to mitigate its commodity price exposure on
a portion of its natural gas production. These fixed price
forward gas sales are considered normal sales in the ordinary
course of business and outside the scope of FASB ASC Topic 815,
Derivatives and Hedging (FASB ASC 815).
Effective November 3, 2008, the Company changed its method
of accounting for natural gas commodity derivatives to reflect
unrealized gains and losses on commodity derivative contracts in
the income statement rather than on the balance sheet. The
Company previously followed hedge accounting for its natural gas
17
hedges. Under this prior accounting method, the unrealized gain
or loss on qualifying cash flow hedges (calculated on a mark to
market basis, net of tax) was recorded on the balance sheet in
stockholders equity as accumulated other comprehensive
income (loss). When an unrealized hedging gain or loss was
realized upon contract expiration, it was reclassified into
earnings through inclusion in natural gas sales revenues. The
Company continues to record the fair value of its commodity
derivatives as an asset or liability on the Consolidated Balance
Sheets, but records the changes in the fair value of its
commodity derivatives in the Consolidated Statements of
Operations as an unrealized gain or loss on commodity
derivatives. There is no resulting effect on overall cash flow,
total assets, total liabilities or total stockholders
equity, and there is no impact on any of the financial covenants
under the Companys Senior Credit Facility, 2008 Senior
Notes or 2009 Senior Notes (See Note 3).
During the first quarter of 2009, the Company converted its
physical, fixed price, forward natural gas sales to physical,
indexed natural gas sales combined with financial swaps whereby
the Company receives the fixed price and pays the variable
price. This change provides operational flexibility to curtail
gas production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010.
Fair Value Measurements. The Company follows
FASB ASC Topic 820, Fair Value Measurements and Disclosures
(FASB ASC 820). Under FASB ASC 820, fair
value is defined as the price that would be received to sell an
asset or paid to transfer a liability in an orderly transaction
between market participants at measurement date and establishes
a three level hierarchy for measuring fair value. The valuation
assumptions utilized to measure the fair value of the
Companys commodity derivatives were observable inputs
based on market data obtained from independent sources and are
considered Level 2 inputs (quoted prices for similar
assets, liabilities (adjusted) and market-corroborated inputs).
In consideration of counterparty credit risk, the Company
assessed the possibility of whether each counterparty to the
derivative would default by failing to make any contractually
required payments as scheduled in the derivative instrument in
determining the fair value. Additionally, the Company considers
that it is of substantial credit quality and has the financial
resources and willingness to meet its potential repayment
obligations associated with the derivative transactions.
The fair values summarized below were determined in accordance
with the requirements of FASB ASC 820 and we aligned the
categories below with the Level 1, 2, and 3 fair value
measurements as defined by the Fair Value Measurements and
Disclosures Topic . The balance of net unrealized gains and
losses recognized for our energy-related derivative instruments
at March 31, 2010 is summarized in the following table
based on the inputs used to determine fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1(a)
|
|
Level 2(b)
|
|
Level 3(c)
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative asset
|
|
$
|
|
|
|
$
|
93,292
|
|
|
$
|
|
|
|
$
|
93,292
|
|
Non-current derivative asset
|
|
$
|
|
|
|
$
|
15,889
|
|
|
$
|
|
|
|
$
|
15,889
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liability
|
|
$
|
|
|
|
$
|
1,068
|
|
|
$
|
|
|
|
$
|
1,068
|
|
Non-current derivative liability
|
|
$
|
|
|
|
$
|
4,717
|
|
|
$
|
|
|
|
$
|
4,717
|
|
|
|
|
(a) |
|
Values represent observable unadjusted quoted prices for traded
instruments in active markets. |
|
|
|
(b) |
|
Values with inputs that are observable directly or indirectly
for the instrument, but do not qualify for Level 1. |
|
(c) |
|
Values with a significant amount of inputs that are not
observable for the instrument. |
Asset Retirement Obligation. The
Companys asset retirement obligations (ARO)
consist primarily of estimated costs of dismantlement, removal,
site reclamation and similar activities associated with its oil
and natural gas properties. FASB ASC Topic 410, Asset Retirement
and Environmental Obligations (FASB ASC 410)
requires that the discounted fair value of a liability for an
ARO be recognized in the period in
18
which it is incurred with the associated asset retirement cost
capitalized as part of the carrying cost of the oil and natural
gas asset. The recognition of an ARO requires that management
make numerous estimates, assumptions and judgments regarding
such factors as the existence of a legal obligation for an ARO,
estimated probabilities, amounts and timing of settlements; the
credit-adjusted, risk-free rate to be used; inflation rates, and
future advances in technology. In periods subsequent to initial
measurement of the ARO, the Company must recognize
period-to-period
changes in the liability resulting from the passage of time and
revisions to either the timing or the amount of the original
estimate of undiscounted cash flows. Increases in the ARO
liability due to passage of time impact net income as accretion
expense. The related capitalized costs, including revisions
thereto, are charged to expense through DD&A.
Share-Based Payment Arrangements. The Company
applies FASB ASC Topic 718, Compensation Stock
Compensation (FASB ASC 718), which requires the
measurement and recognition of compensation expense for all
share-based payment awards made to employees and directors,
including employee stock options, based on estimated fair
values. Share-based compensation expense recognized for the
three months ended March 31, 2010 and 2009 was
$2.8 million and $2.1 million, respectively. At
March 31, 2010, there was $3.1 million of total
unrecognized compensation cost related to non-vested share-based
compensation arrangements granted under stock option plans. That
cost is expected to be recognized over a weighted average period
of 0.79 years. See Note 4 for additional information.
FASB ASC 718, requires companies to estimate the fair value
of share-based payment awards on the date of grant using an
option-pricing model. The Company utilized a Black-Scholes
option pricing model to measure the fair value of stock options
granted to employees. The value of the portion of the award that
is ultimately expected to vest is recognized as expense over the
requisite service period in the Companys Consolidated
Statement of Operations. The Companys determination of
fair value of share-based payment awards on the date of grant
using an option-pricing model is affected by the Companys
stock price as well as assumptions regarding a number of highly
complex and subjective variables. These variables include, but
are not limited to, the Companys expected stock price
volatility over the term of the awards and actual and projected
employee stock option exercise behaviors.
Full Cost Method of Accounting. The Company
uses the full cost method of accounting for oil and gas
operations whereby all costs associated with the exploration for
and development of oil and gas reserves are capitalized on a
country-by-country
basis. Such costs include land acquisition costs, geological and
geophysical expenses, carrying charges on non-producing
properties, costs of drilling both productive and non-productive
wells and overhead charges directly related to acquisition,
exploration and development activities. Substantially all of the
oil and gas activities are conducted jointly with others and,
accordingly, the amounts reflect only the Companys
proportionate interest in such activities.
Companies that use the full cost method of accounting for oil
and natural gas exploration and development activities are
required to perform a ceiling test calculation each quarter. The
full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test is performed quarterly, on a
country-by-country
basis, utilizing the average of prices in effect on the first
day of the month for the preceding twelve month period in
accordance with SEC Release
No. 33-8995.
The ceiling limits such pooled costs to the aggregate of the
present value of future net revenues attributable to proved
crude oil and natural gas reserves discounted at 10% plus the
lower of cost or market value of unproved properties less any
associated tax effects. If such capitalized costs exceed the
ceiling, the Company will record a write-down to the extent of
such excess as a non-cash charge to earnings. Any such
write-down will reduce earnings in the period of occurrence and
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 Company did not have any write-downs related to the full
cost ceiling limitation during the three months ended
March 31, 2010. During the first quarter of 2009, the
Company recorded a $1.0 billion ($673.0 million net of
tax) non-cash write-down of the carrying value of the
Companys proved oil and gas properties as of
March 31, 2009, as a result of the ceiling test limitation,
which is reflected as write-down of proved oil and gas
properties in the accompanying consolidated statements of
operations. The March 31, 2009 ceiling test limitation was
calculated prior to the adoption of SEC Release
No. 33-8995
and was based on
19
prices in effect on the last day of the reporting period,
March 31, 2009, reflecting wellhead prices of $2.47 per Mcf
for natural gas and $33.91 per barrel for condensate.
The calculation of the ceiling test is based upon estimates of
proved reserves. There are numerous uncertainties inherent in
estimating quantities of proved reserves, in projecting the
future rates of production and in the timing of development
activities. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling,
testing and production subsequent to the date of the estimate
may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and
natural gas that are ultimately recovered.
Capitalized Interest. Interest is capitalized
on the cost of unevaluated gas and oil properties that are
excluded from amortization and actively being evaluated.
RESULTS
OF OPERATIONS
QUARTER
ENDED MARCH 31, 2010 VS. QUARTER ENDED MARCH 31,
2009
During the quarter ended March 31, 2010, production
increased 15% on a gas equivalent basis to 48.5 Bcfe from
42.1 Bcfe for the same quarter in 2009 attributable to the
Companys successful drilling activities during 2009 and in
the first three months of 2010. Realized natural gas prices,
including realized gains and losses on commodity derivatives,
increased 20% to $5.37 per Mcf in the first quarter of 2010 as
compared to $4.46 per Mcf for the same quarter of 2009. During
the three months ended March 31, 2010, the Companys
average price for natural gas was $5.38 per Mcf, excluding
realized gains and losses on commodity derivatives as compared
to $3.95 per Mcf for the same period in 2009. The increase in
average natural gas prices along with the increase in production
contributed to a 63% increase in revenues to $273.1 million
as compared to $168.0 million in 2009.
Lease operating expense (LOE) remained flat at
$10.3 million during the first quarter of 2010 compared to
$10.2 million during the same period in 2009. On a unit of
production basis, LOE costs decreased to $0.21 per Mcfe at
March 31, 2010 compared to $0.24 per Mcfe at March 31,
2009 largely as a result of increased production volumes during
the quarter ended March 31, 2010.
During the three months ended March 31, 2010, production
taxes were $28.4 million compared to $17.4 million
during the same period in 2009, or $0.59 per Mcfe compared to
$0.41 per Mcfe. The increase in per unit taxes is attributable
to increased sales revenues as a result of increased realized
gas prices during the quarter ended March 31, 2010 as
compared to the same period in 2009. Production taxes are
calculated based on a percentage of revenue from production and
were 10.4% of revenues for the quarter ended March 31, 2010
and 10.3% for the same period in 2009.
Gathering fees increased to $12.0 million for the three
months ended March 31, 2010 compared to $10.8 million
during the same period in 2009 largely due to increased
production volumes. On a per unit basis, gathering fees
decreased to $0.25 per Mcfe for the three months ended
March 31, 2010 as compared to $0.26 during the same period
in 2009.
To secure pipeline infrastructure providing sufficient capacity
to transport a portion of the Companys natural gas
production away from southwest Wyoming and to provide for
reasonable basis differentials for its natural gas, the Company
incurred firm transportation charges totaling $15.9 million
for the quarter ended March 31, 2010 as compared to
$13.4 million for the same period in 2009 in association
with Rockies Express Pipeline (REX) transportation
charges. On a per unit basis, transportation charges increased
to $0.33 per Mcfe (on total company volumes) for the three
months ended March 31, 2010 as compared to $0.32 per Mcfe
(on total company volumes) for the same period in 2009 due to
increased transportation rates as a result of further eastern
expansion of REX.
Depletion, depreciation and amortization (DD&A)
expenses decreased to $51.3 million during the three months
ended March 31, 2010 from $60.7 million for the same
period in 2009, attributable to a lower depletion rate due
mainly to a lower depletable base as a result of the ceiling
test write-down during the first quarter of 2009 and partially
offset by increased production volumes. On a unit of production
basis, DD&A
20
decreased to $1.06 per Mcfe for the quarter ended March 31,
2010 from $1.44 for the quarter ended March 31, 2009. The
Company recorded a $1.0 billion non-cash write-down of the
carrying value of the Companys proved oil and gas
properties at March 31, 2009 as a result of ceiling test
limitations. The write-down reduced earnings in the first
quarter of 2009 and results in lower DD&A expense in future
periods.
General and administrative expenses increased to
$6.4 million for the quarter ended March 31, 2010
compared to $4.6 million for the same period in 2009. The
increase in general and administrative expenses is primarily
attributable to increased headcount and related compensation. On
a per unit basis, general and administrative expenses were $0.13
per Mcfe for the quarter ended March 31, 2010 compared with
$0.11 per Mcfe for the same period in 2009.
Interest expense increased to $11.7 million during the
quarter ended March 31, 2010 compared to $7.3 million
during the same period in 2009 as a result of increased
borrowings during the period ended March 31, 2010. At
March 31, 2010, the Company had $1.0 billion in
borrowings outstanding. In addition, the Company capitalized
$2.2 million in interest expense for the three months ended
March 31, 2010 related to unevaluated oil and gas
properties. There was no capitalized interest for the same
period in 2009.
During the quarter ended March 31, 2010, the Company
recognized $0.7 million of realized loss on commodity
derivatives as compared to $20.4 million of realized gain
on commodity derivatives during the quarter ended March 31,
2009. The realized gain or loss on commodity derivatives relates
to actual amounts received or paid under these derivative
contracts.
During the quarter ended March 31, 2010, the Company
recognized $182.0 million in unrealized gain on commodity
derivatives as compared to $186.1 million in unrealized
gain on commodity derivatives during the quarter ended
March 31, 2009. The unrealized gain or loss on commodity
derivatives represents the change in the fair value of these
derivative instruments.
Other expense for the quarter ended March 31, 2009 includes
rig termination payments of $3.1 million that were not
incurred during the same period in 2010.
The Company recognized income before income taxes of
$318.6 million for the quarter ended March 31, 2010
compared with a net loss before income tax benefit of
$789.5 million for the same period in 2009. The increase in
earnings is primarily a result of the non-cash write-down of oil
and gas properties associated with the ceiling test limitation
during the first quarter of 2009, increased natural gas prices
and increased production during the three months ended
March 31, 2010 as compared to the same period in 2009.
The income tax provision recognized for the quarter ended
March 31, 2010 was $116.3 million compared with an
income tax benefit of $276.9 million for the three months
ended March 31, 2009. The increase is largely due to
increased income during the quarter ended March 31, 2010
compared with a a net loss before income tax benefit of
$789.5 million primarily as a result of the non-cash
write-down of oil and gas properties associated with the ceiling
test limitation during the quarter ended March 31, 2009.
The effective tax rate for the quarter ended March 31, 2010
increased as compared to the prior period primarily due to
elevated activity levels in the higher state tax rate
jurisdiction of Pennsylvania which increased the overall
effective tax rate to 35.5%. A one-time
catch-up was
required which caused the effective tax rate for the quarter
ended March 31, 2010 to increase to 36.5%.
For the three months ended March 31, 2010, the Company
recognized net income of $202.4 million or $1.31 per
diluted share as compared with net loss of $512.6 million
or ($3.39) per diluted share for the same period in 2009. The
increase is primarily attributable to the non-cash write-down of
oil and gas properties associated with the ceiling test
limitation during the quarter ended March 31, 2009,
increased natural gas prices and increased production during the
three months ended March 31, 2010 as compared to the same
period in 2009.
The discussion and analysis of the Companys financial
condition and results of operations is based upon consolidated
financial statements, which have been prepared in accordance
with U.S. GAAP. In addition, application of generally
accepted accounting principles requires the use of estimates,
judgments and assumptions that affect the reported amounts of
assets and liabilities as of the date of the financial
statements as well
21
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 three month period ended March 31, 2010, the
Company relied on cash provided by operations along with
borrowings under the senior credit facility and the issuance of
the 2010 Senior Notes to finance its capital expenditures. The
Company participated in the drilling of 118 wells in
Wyoming and Pennsylvania. For the three month period ended
March 31, 2010, total capital expenditures were
$546.7 million ($333.0 upon closing of the purchase of
additional acreage in the Pennsylvania Marcellus Shale,
$198.6 million related to oil and gas development
expenditures and $15.2 million related to gathering system
expenditures).
At March 31, 2010, the Company reported a cash position of
$6.0 million compared to $14.4 million at
March 31, 2009. Working capital deficit at March 31,
2010 was $65.5 million compared to working capital of
$84.7 million at March 31, 2009. At March 31,
2010, we had $11.0 million in outstanding borrowings and
$489.0 million of available borrowing capacity under our
credit facility. In addition, the Company had
$500.0 million, $235.0 million and $300.0 million
outstanding under its 2010 Senior Notes, 2009 Senior Notes and
2008 Senior Notes, respectively (See Note 3). Other
long-term obligations of $51.6 million at March 31,
2010 is comprised of items payable in more than one year,
primarily related to production taxes and our asset retirement
obligation.
The Companys positive cash provided by operating
activities, along with availability under the senior credit
facility, are projected to be sufficient to fund the
Companys budgeted capital investment program for 2010,
which is currently projected to be $1.1 billion. Of the
$1.1 billion budget, the Company plans to allocate
approximately 60% to Wyoming and 40% to Pennsylvania.
On February 22, 2010, the Company closed the purchase of
additional acreage in the Pennsylvania Marcellus Shale for
$333.0 million in order to increase the scale of its
Marcellus position. This transaction is incremental to the 2010
budgeted capital investment program discussed above. In
addition, the Company traded and consolidated its land position
in Pennsylvania during the first quarter of 2010, which resulted
in net proceeds of $68.4 million.
After the acquisition of 78,221 acres in the Marcellus
Shale and consolidation of the Companys land position in
Pennsylvania for net proceeds of $68.4 million during the
first quarter of 2010, the Companys undeveloped acreage
position in Pennsylvania is approximately 225,000 net
undeveloped acres.
Additionally, on January 28, 2010, the Companys
subsidiary, Ultra Resources, Inc., agreed to issue an aggregate
amount of $500.0 million of Senior Notes (the 2010
Senior Notes) pursuant to a Second Supplement to its
Master Note Purchase Agreement dated March 6, 2008. Of the
2010 Senior Notes, $270.0 million were issued
January 28, 2010 and $230.0 million were issued
February 16, 2010. The 2010 Senior Notes rank pari passu
with Ultra Resources bank revolving credit facility and
other outstanding Senior Notes. Proceeds from the 2010 Senior
Notes were used to repay revolving credit facility debt, but did
not reduce the borrowings available under the revolving credit
facility, and for general corporate purposes, including funding
the Pennsylvania Marcellus Shale acquisition that closed on
February 22, 2010.
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
22
LIBOR rate, plus a margin based on a grid of our consolidated
leverage ratio (100.0 basis points per annum as of
March 31, 2010).
At March 31, 2010, we had $11.0 million in outstanding
borrowings and $489.0 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 March 31, 2010, we were in compliance with all
of our debt covenants under our credit facility.
Senior Notes: On March 6, 2008, the
Companys wholly-owned subsidiary, Ultra Resources, Inc.
issued $300.0 million Senior Notes (the 2008 Senior
Notes) pursuant to a Master Note Purchase Agreement
between the Company and the purchasers of the Notes. On
March 5, 2009, Ultra Resources, Inc., issued
$235.0 million Senior Notes (the 2009 Senior
Notes) pursuant to a First Supplement to the Master Note
Purchase Agreement. And, on January 28, 2010, Ultra
Resources, Inc., agreed to issue an aggregate amount of
$500.0 million of Senior Notes (the 2010 Senior
Notes) pursuant to a Second Supplement to the Master Note
Purchase Agreement. Of the 2010 Senior Notes,
$270.0 million were issued on January 28, 2010 and
$230.0 million were issued on February 16, 2010.
The Senior Notes rank pari passu with the Companys bank
credit facility. Payment of the Senior Notes is guaranteed by
Ultra Petroleum Corp. and UP Energy Corporation.
Proceeds from the sale of the 2010 Senior Notes were used to
repay revolving credit facility debt, but did not reduce the
borrowings available to the Company under the revolving credit
facility, and for general corporate purposes, including funding
the Pennsylvania Marcellus Shale acquisition that closed on
February 22, 2010. The Senior Notes are pre-payable in
whole or in part at any time and are subject to representations,
warranties, covenants and events of default customary for a
senior note financing. At March 31, 2010, the Company was
in compliance with all of its debt covenants under the Master
Note Purchase Agreement.
Operating Activities. During the three months
ended March 31, 2010, net cash provided by operating
activities was $168.7 million, a 28% increase from
$131.9 million for the same period in 2009. The increase in
net cash provided by operating activities is largely
attributable to the increase in realized natural gas prices and
increased production during the three months ended
March 31, 2010 as compared to the same period in 2009.
Investing Activities. During the three months
ended March 31, 2010, net cash used in investing activities
was $422.7 million as compared to $281.4 million for
the same period in 2009. The increase in net cash used in
investing activities is largely due to increased capital
investments associated with the Pennsylvania Marcellus Shale
acquisition in February 2010 and the Companys drilling
activities in 2010 as compared to 2009, partially offset by the
proceeds from the sale of undeveloped acreage during the quarter
ended March 31, 2010.
Financing Activities. During the three months
ended March 31, 2010, net cash provided by financing
activities was $245.8 million as compared to
$149.7 million for the same period in 2009. The increase in
cash provided by net financing activities is primarily
attributable to increased borrowings, primarily attributable to
the 2010 Senior Notes offering, during the three months ended
March 31, 2010 as compared to the same period in 2009.
OFF
BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as
of March 31, 2010.
23
CAUTIONARY
STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended,
Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. All statements
other than statements of historical facts included in this
document, including without limitation, statements in
Managements Discussion and Analysis of Financial Condition
and Results of Operations regarding our financial position,
estimated quantities and net present values of reserves,
business strategy, plans and objectives of the Companys
management for future operations, covenant compliance and those
statements preceded by, followed by or that otherwise include
the words believe, expects,
anticipates, intends,
estimates, projects, target,
goal, plans, objective,
should, or similar expressions or variations on such
expressions are forward-looking statements. The Company can give
no assurances that the assumptions upon which such
forward-looking statements are based will prove to be correct
nor can the Company assure adequate funding will be available to
execute the Companys planned future capital program.
Other risks and uncertainties include, but are not limited to,
fluctuations in the price the Company receives for oil and gas
production, reductions in the quantity of oil and gas sold due
to increased industry-wide demand
and/or
curtailments in production from specific properties due to
mechanical, marketing or other problems, operating and capital
expenditures that are either significantly higher or lower than
anticipated because the actual cost of identified projects
varied from original estimates
and/or from
the number of exploration and development opportunities being
greater or fewer than currently anticipated and increased
financing costs due to a significant increase in interest rates.
We are also subject to risks associated with the current
unprecedented volatility in the financial markets, including the
duration of the crisis and effectiveness of government
solutions. See the Companys annual report on
Form 10-K
for the year ended December 31, 2009 for additional risks
related to the Companys business.
ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Objectives and Strategy: The Companys
major market risk exposure is in the pricing applicable to its
natural gas and oil production. Realized pricing is currently
driven primarily by the prevailing price for the Companys
Wyoming natural gas production. Historically, prices received
for natural gas production have been volatile and unpredictable.
Pricing volatility is expected to continue.
The Company relies on various types of derivative instruments to
manage its exposure to commodity price risk and to provide a
level of certainty in the Companys forward cash flows
supporting the Companys capital investment program.
Commodity Derivative Contracts: During the
first quarter of 2009, the Company converted its physical, fixed
price, forward natural gas sales to physical, indexed natural
gas sales combined with financial swaps whereby the Company
receives the fixed price and pays the variable price. This
change provides operational flexibility to curtail gas
production in the event of continued declines in natural gas
prices. The contracts were converted at no cost to the Company
and the conversion of these contracts to derivative instruments
was effective upon entering into these transactions in March
2009, with upcoming settlements for production months through
December 2010. The natural gas reference prices of these
commodity derivative contracts are typically referenced to
natural gas index prices as published by independent third
parties.
From time to time, the Company also utilizes fixed price forward
gas sales to manage its commodity price exposure. These fixed
price forward gas sales are considered normal sales in the
ordinary course of business and outside the scope of FASB
ASC 815, Derivatives and Hedging.
Fair Value of Commodity Derivatives: FASB
ASC 815 requires that all derivatives be recognized on the
balance sheet as either an asset or liability and be measured at
fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. The Company does not apply hedge
accounting to any of its derivative instruments. The application
of hedge accounting was discontinued by the Company for periods
beginning on or after November 3, 2008.
24
Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at
fair value on the balance sheet and the associated unrealized
gains and losses are recorded as current expense or income in
the income statement. Unrealized gains or losses on commodity
derivatives represent the non-cash change in the fair value of
these derivative instruments and does not impact operating cash
flows on the cash flow statement.
At March 31, 2010, the Company had the following open
commodity derivative contracts to manage price risk on a portion
of its natural gas production whereby the Company receives the
fixed price and pays the variable price. See Note 7 for the
detail of the asset and liability values of the following
derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
Volume -
|
|
Average
|
|
March 31,
|
Type
|
|
Point of Sale
|
|
Remaining Contract Period
|
|
MMBTU/Day
|
|
Price/MMBTU
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
Asset/(Liability)
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010
|
|
|
50,000
|
|
|
$
|
4.99
|
|
|
$
|
14,097
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2010 2011
|
|
|
160,000
|
|
|
$
|
5.00
|
|
|
$
|
44,741
|
|
Swap
|
|
NW Rockies
|
|
Calendar 2011
|
|
|
10,000
|
|
|
$
|
6.27
|
|
|
$
|
4,535
|
|
Swap
|
|
NW Rockies
|
|
Apr 2010 Oct 2010
|
|
|
50,000
|
|
|
$
|
5.05
|
|
|
$
|
13,696
|
|
Swap
|
|
Northeast
|
|
Calendar 2010 2011
|
|
|
30,000
|
|
|
$
|
6.38
|
|
|
$
|
26,327
|
|
The following table summarizes the pre-tax realized and
unrealized gains and losses the Company recognized related to
its natural gas derivative instruments in the Consolidated
Statements of Operations for the three months ended
March 31, 2010 and 2009 (refer to Note 1 for details
of unrealized gains or losses included in accumulated other
comprehensive income in the Consolidated Balance Sheets):
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
|
|
Ended March 31,
|
|
Natural Gas Commodity Derivatives:
|
|
2010
|
|
|
2009
|
|
|
Realized (loss) gain on commodity derivatives(1)
|
|
$
|
(669
|
)
|
|
$
|
20,355
|
|
Unrealized gain on commodity derivatives(1)
|
|
|
182,020
|
|
|
|
186,073
|
|
|
|
|
|
|
|
|
|
|
Total gain on commodity derivatives
|
|
$
|
181,351
|
|
|
$
|
206,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in gain on commodity derivatives in the Consolidated
Statements of Operations. |
ITEM 4
CONTROLS AND PROCEDURES
|
|
(a)
|
Evaluation
of Disclosure Controls and Procedures
|
We have performed an evaluation under the supervision and with
the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures, as
defined in
Rule 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act). Our disclosure controls and procedures are the
controls and other procedures that we have designed to ensure
that we record, process, accumulate and communicate information
to our management, including our Chief Executive Officer and
Chief Financial Officer, to allow timely decisions regarding
required disclosures and submissions within the time periods
specified in the SECs rules and forms. All internal
control systems, no matter how well designed, have inherent
limitations. Therefore, even those determined to be effective
can provide only a reasonable assurance with respect to
financial statement preparation and presentation. Based on the
evaluation, our management, including our Chief Executive
Officer and Chief Financial Officer, concluded that our
disclosure controls and procedures were effective as of
March 31, 2010. There were no changes in our internal
control over financial reporting during the three months ended
March 31, 2010 that have materially affected or are
reasonably likely to affect, our internal control over financial
reporting.
25
PART II
OTHER INFORMATION
ITEM 1. LEGAL
PROCEEDINGS
The Company is currently involved in various routine disputes
and allegations incidental to its business operations. While it
is not possible to determine the ultimate disposition of these
matters, the Company believes that the resolution of all such
pending or threatened litigation is not likely to have a
material adverse effect on the Companys financial
position, or results of operations.
ITEM 1A. RISK
FACTORS
There have been no material changes with respect to the risk
factors disclosed in our Annual Report on
Form 10-K
for the fiscal year ended December 31, 2009 except for the
update described below.
Climate change legislation or regulations restricting
emissions of greenhouse gasses could result in
increased operating costs and reduced demand for the oil and gas
we produce.
On December 15, 2009, the U.S. Environmental
Protection Agency (EPA) officially published
its findings that emissions of carbon dioxide, methane and other
greenhouse gases present an endangerment to public
health and the environment because emissions of such gases are,
according to the EPA, contributing to warming of the
earths atmosphere and other climatic changes. These
findings allow the EPA to adopt and implement regulations that
would restrict emissions of greenhouse gases under existing
provisions of the federal Clean Air Act. Accordingly, the EPA
has proposed two sets of regulations that would require a
reduction in emissions of greenhouse gases from motor vehicles
and could trigger permit review for greenhouse gas emissions
from certain stationary sources.
In addition, on October 30, 2009, the EPA published a final
rule requiring the reporting of greenhouse gas emissions from
specified large greenhouse gas emission sources in the United
States beginning in 2011 for emissions occurring in 2010. On
March 23, 2010, the EPA announced that it will be proposing
a rule to extend this reporting obligation to oil and gas
facilities, including onshore and offshore oil and gas
production facilities.
Also, on June 26, 2009, the U.S. House of
Representatives passed the American Clean Energy and
Security Act of 2009, or ACESA, which would
establish an economy-wide
cap-and-trade
program to reduce U.S. emissions of greenhouse gases,
including carbon dioxide and methane. ACESA would require a 17%
reduction in greenhouse gas emissions from 2005 levels by 2020
and just over an 80% reduction of such emissions by 2050. Under
this legislation, the EPA would issue a capped and steadily
declining number of tradable emissions allowances authorizing
emissions of greenhouse gases into the atmosphere. These
reductions would be expected to cause the cost of allowances to
escalate significantly over time. The net effect of ACESA will
be to impose increasing costs on the combustion of carbon-based
fuels such as oil, refined petroleum products, and natural gas.
The U.S. Senate has begun work on its own legislation for
restricting domestic greenhouse gas emissions, and the Obama
Administration has indicated its support for legislation to
reduce greenhouse emissions through an emission allowance
system. At the state level, more than one-third of the states,
either individually or through multi-state regional initiatives,
already have begun implementing legal measures to reduce
emissions of greenhouse gases. The adoption and implementation
of any regulations imposing reporting obligations on, or
limiting emissions of greenhouse gases from, our equipment and
operations could require us to incur costs to accumulate the
required data
and/or
reduce emissions of greenhouse gases associated with our
operations or could adversely affect demand for the oil and
natural gas that we produce.
26
ITEM 6. EXHIBITS
(a) Exhibits
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
28
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: May 5, 2010
|
|
|
|
By:
|
/s/ Marshall
D. Smith
|
Name: Marshall D. Smith
|
|
|
|
Title:
|
Chief Financial Officer
|
Date: May 5, 2010
29
EXHIBIT INDEX
|
|
|
|
|
|
3
|
.1
|
|
Articles of Incorporation of Ultra Petroleum Corp.
(incorporated by reference to Exhibit 3.1 of the
Companys Quarterly Report on Form 10Q for the period
ended June 30, 2001.)
|
|
3
|
.2
|
|
By-Laws of Ultra Petroleum Corp-(incorporated by reference to
Exhibit 3.2 of the Companys Quarterly Report on
Form 10Q for the period ended June 30, 2001.)
|
|
3
|
.3
|
|
Articles of Amendment to Articles of Incorporation of Ultra
Petroleum Corp. (incorporated by reference to Exhibit 3.3
of the Companys Report on
Form 10-K/A
for the period ended December 31, 2005.)
|
|
4
|
.1
|
|
Specimen Common Share Certificate (incorporated by
reference to Exhibit 4.1 of the Companys Quarterly
Report on Form 10Q for the period ended June 30, 2001.)
|
|
31
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1*
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.2*
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
101
|
.INS**
|
|
XBRL Instance Document.
|
|
101
|
.SCH**
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101
|
.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101
|
.LAB**
|
|
XBRL Label Linkbase Document.
|
|
101
|
.PRE**
|
|
XBRL Presentation Linkbase Document.
|
|
|
|
* |
|
Filed or furnished herewith. |
|
** |
|
The documents formatted in XBRL (Extensible Business Reporting
Language) and attached as Exhibit 101 to this report are
deemed not filed or part of a registration statement or
prospectus for purposes of sections 11 or 12 of the
Securities Act, are deemed not filed for purposes of
section 18 of the Exchange Act, and otherwise, not subject
to liability under these sections. |
30