UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004
OR
[ ] 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 0-29370
ULTRA PETROLEUM CORP.
(Exact name of registrant as specified in its charter)
Yukon Territory, Canada N/A
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification number)
363 North Sam Houston Parkway East,
Suite 1200, Houston, Texas 77060
(Address of principal executive offices) (Zip code)
(281) 876-0120
(Registrant's 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 [X] NO [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act)
YES [X] NO [ ]
The number of common shares, without par value, of Ultra Petroleum Corp.,
outstanding as of July 27, 2004 was 75,020,368.
PART 1 - FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
(Expressed in U.S. Dollars)
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Revenues:
Natural gas sales $ 43,174,208 $ 22,001,224 $ 89,251,431 $ 45,123,812
Oil sales 2,936,082 1,464,430 5,477,632 3,012,936
------------ ------------ ------------ ------------
Total operating revenues 46,110,290 23,465,654 94,729,063 48,136,748
Expenses:
Production expenses and taxes 9,424,401 4,973,661 19,149,299 10,175,404
Depletion and depreciation 5,415,985 3,451,894 10,896,704 7,057,740
General and administrative 1,190,350 1,503,772 2,744,388 2,741,475
General and administrative - stock compensation 523,500 405,720 623,523 1,018,220
------------ ------------ ------------ ------------
Total operating expenses 16,554,236 10,335,047 33,413,914 20,992,839
Operating income 29,556,054 13,130,607 61,315,149 27,143,909
Other income (expense):
Interest expense (848,742) (750,834) (1,948,912) (1,404,434)
Interest income 9,910 11,191 22,644 19,768
------------ ------------ ------------ ------------
Total operating income (expense) (838,832) (739,643) (1,926,268) (1,384,666)
Income for the period, before income tax provision 28,717,222 12,390,964 59,388,881 25,759,243
Income tax provision - deferred 10,194,718 4,770,909 21,083,159 9,917,697
Net income for the period 18,522,504 7,620,055 38,305,722 15,841,546
Retained earnings, beginning of period 75,921,734 19,037,368 56,138,516 10,815,877
------------ ------------ ------------ ------------
Retained earnings, end of period $ 94,444,238 $ 26,657,423 $ 94,444,238 $ 26,657,423
============ ============ ============ ============
Income per common share - basic $ 0.25 $ 0.10 $ 0.51 $ 0.21
============ ============ ============ ============
Income per common share - fully diluted $ 0.23 $ 0.10 $ 0.48 $ 0.20
============ ============ ============ ============
Weighted average common shares outstanding - basic 74,964,830 74,172,652 74,861,087 74,115,066
============ ============ ============ ============
Weighted average common shares outstanding - fully diluted 79,945,429 78,303,218 79,857,697 78,121,136
============ ============ ============ ============
2
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Expressed in U.S. Dollars)
Six Months Ended
June 30,
-------------------------------
2004 2003
------------ ------------
Cash provided by (used in):
Operating activities:
Net income for the period $ 38,305,722 $ 15,841,546
Add (deduct)
Items not involving cash:
Depletion and depreciation 10,896,704 7,057,740
Deferred income taxes 21,083,159 9,917,697
Stock compensation 623,523 1,018,220
Net changes in non-cash working capital:
Restricted cash (629) (726)
Accounts receivable 1,588,509 (564,995)
Inventory 4,073,175 --
Prepaid expenses and other current assets (3,641,480) (2,233,743)
Accounts payable and accrued liabilities (9,279,205) (524,177)
Other long-term obligations 2,699,709 2,242,178
------------ ------------
Cash provided by operating activities 66,349,187 32,753,740
Investing activities:
Oil and gas property expenditures (63,673,697) (29,596,381)
Oil and gas property expenditures in accounts payable (10,458,509) 10,139,414
Purchase of capital assets (634,196) (533,884)
------------ ------------
Cash provided (used) by investing activities (74,766,402) (19,990,851)
Financing activities:
Borrowings on long-term debt, gross 24,000,000 3,000,000
Payments on long-term debt, gross (9,000,000) (17,000,000)
Proceeds from exercise of options 744,413 474,947
------------ ------------
Cash provided (used) by financing activities 15,744,413 (13,525,053)
Increase in cash during the period 7,327,198 (762,164)
Cash and cash equivalents, beginning of period 1,834,112 1,417,711
------------ ------------
Cash and cash equivalents, end of period $ 9,161,310 $ 655,547
============ ============
3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Expressed in U.S. Dollars)
June 30, December 31,
2004 2003
------------- -------------
Assets
Current assets
Cash and cash equivalents $ 9,161,310 $ 1,834,112
Restricted cash 211,298 210,669
Accounts receivable 17,760,352 19,348,861
Current deferred tax asset 2,999,077 --
Inventory 9,516,095 13,589,270
Prepaid expenses and other current assets 5,353,217 1,711,737
------------- -------------
Total current assets 45,001,349 36,694,649
Oil and gas properties, using the full cost method of
accounting 361,250,693 307,863,722
Capital assets 1,523,498 1,212,006
------------- -------------
Total assets $ 407,775,540 $ 345,770,377
============= =============
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities $ 14,324,191 $ 23,353,323
Fair value of derivative instrument liability 8,448,102 4,781,068
Capital costs accrual 20,158,403 30,616,912
------------- -------------
Total current liabilities 42,930,696 58,751,303
Bank indebtness 114,000,000 99,000,000
Deferred income taxes 52,402,606 33,446,131
Other long-term obligations 9,915,533 5,120,213
Shareholders' equity
Share capital 102,076,812 97,448,221
Treasury stock (1,193,650) (1,193,650)
Other comprehensive loss - fair value of derivative
instruments (6,800,695) (2,940,357)
Retained earnings 94,444,238 56,138,516
------------- -------------
Total shareholders' equity 188,526,705 149,452,730
------------- -------------
Total liabilities and shareholders' equity $ 407,775,540 $ 345,770,377
============= =============
4
ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(All dollar amounts in this Quarterly Report on Form 10-Q are expressed in U.S.
dollars unless otherwise noted)
DESCRIPTION OF THE BUSINESS:
Ultra Petroleum Corp. (the "Company") is an independent oil and gas company
engaged in the acquisition, exploration, development, and production of oil and
gas properties. The Company was originally incorporated under the laws of
British Columbia, Canada. On March 1, 2000, the Company was continued under the
laws of the Yukon Territory, Canada. The Company's principal business activities
are in the Green River Basin of southwest Wyoming and Bohai Bay, China.
1. SIGNIFICANT ACCOUNTING POLICIES:
The accompanying financial statements, other than the balance sheet data as of
December 31, 2003, are unaudited and were prepared from the Company's records.
Balance sheet data as of December 31, 2003 was derived from the Company's
audited financial statements, but does not include all disclosures required by
U.S. generally accepted accounting principles. The Company's management believes
that these financial statements include all adjustments necessary for a fair
presentation of the Company's financial position and results of operations. All
adjustments are of a normal and recurring nature unless specifically noted. The
Company prepared these financial statements on a basis consistent with the
Company's annual audited financial 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 related notes included in the Company's most recent annual report
on Form 10-K.
(a) Basis of presentation and principles of consolidation:
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries, UP Energy Corporation, Ultra Resources, Inc., and
Sino-American Energy Corporation. The Company presents its financial statements
in accordance with accounting principles generally accepted in the United States
("US GAAP"). All material inter-company transactions and balances have been
eliminated upon consolidation.
(b) Accounting principles:
The consolidated financial statements are prepared in accordance with accounting
principles generally accepted in the United States.
(c) Cash and cash equivalents:
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.
(d) 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.
(e) Capital assets:
Capital assets are recorded at cost and depreciated using the declining-balance
method based on a seven-year useful life.
(f) Oil and gas properties:
The Company uses the full cost method of accounting for oil and gas operations
whereby all costs associated with the exploration for and development of oil and
gas reserves are capitalized to the Company's cost centers. 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. The Company conducts operations in both the United
States and China. Separate cost centers are maintained for each country in which
the Company has operations.
The capitalized costs, together with the costs of production equipment, are
depleted using the units-of-production method based on the proven reserves as
determined by independent petroleum engineers. Oil and gas reserves and
production are converted into equivalent units based upon relative energy
content.
Costs of acquiring and evaluating unproved properties are initially excluded
from the costs subject to depletion. These unproved properties are assessed
periodically to ascertain whether impairment has occurred. When proved reserves
are assigned or the property is considered to be impaired, the cost of the
property or the amount of the impairment is added to the costs subject to
depletion.
The total capitalized cost of oil and gas properties less accumulated depletion
is limited to an amount equal to the estimated future net cash flows from proved
reserves, discounted at 10%, using year-end prices, plus the cost (net of
impairment) of unproved properties as adjusted for related tax effects (the
"full cost ceiling test limitation").
Proceeds from the sale of oil and gas properties are applied against capitalized
costs, with no gain or loss recognized, unless such a sale would significantly
alter the rate of depletion.
Substantially all of the Company's exploration, development and production
activities are conducted jointly with others and, accordingly, these financial
statements reflect only the Company's proportionate interest in such activities.
5
(g) Derivative transactions:
The Company has entered into commodity price risk management transactions to
manage its exposure to gas price volatility. These transactions are in the form
of price swaps with financial institutions or other credit worthy counter
parties. These transactions have been designated by the Company as cash flow
hedges. As such, unrealized gains and losses related to the change in fair
market value of the derivative contracts are recorded in other comprehensive
income in the balance sheet. The Company also enters into forward sales of
physical gas volumes to credit worthy purchasers which are not reflected on the
balance sheet.
(h) Income taxes:
The Company uses the asset and liability method of accounting for income taxes
under which deferred tax assets and liabilities are recognized for future tax
consequences. Accordingly, deferred tax liabilities and assets are determined
based on the temporary differences between the financial statement and tax basis
of assets and liabilities, using the enacted tax rates in effect for the year in
which the differences are expected to reverse.
(i) Earnings per share:
Basic earnings per share is computed by dividing net earnings attributable to
common stock by the weighted average number of common shares outstanding during
each period. Diluted earnings per share is computed by adjusting the average
number of common shares outstanding for the dilutive effect, if any, of stock
options. The Company uses the treasury stock method to determine the dilutive
effect.
The following table provides a reconciliation of the components of basic and
diluted net income per common share:
Three Months Ended Six Months Ended
------------------------------ ------------------------------
June 30, 2004 June 30, 2003 June 30, 2004 June 30, 2003
------------- ------------- ------------- -------------
Net income $18,522,504 $ 7,620,055 $38,305,722 $15,841,546
=========== =========== =========== ===========
Weighted average common shares
outstanding during the period 74,964,830 74,172,652 74,861,087 74,115,066
Effect of dilutive instruments 4,980,599 4,130,566 4,996,610 4,006,070
----------- ----------- ----------- -----------
Weighted average common shares outstanding
during the period including the effects
of dilutive instruments 79,945,429 78,303,218 79,857,697 78,121,136
=========== =========== =========== ===========
Basic earnings per share $ 0.25 $ 0.10 $ 0.51 $ 0.21
=========== =========== =========== ===========
Diluted earnings per share $ 0.23 $ 0.10 $ 0.48 $ 0.20
=========== =========== =========== ===========
(j) Use of estimates:
Preparation of consolidated financial statements in accordance with US 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) Reclassifications:
Certain amounts in the financial statements of the prior years have been
reclassified to conform to the current year financial statement presentation.
(l) Accounting for stock-based compensation:
Statement of Financial Accounting Standards No. 123, "Accounting for Stock -
Based Compensation" (SFAS No. 123), defines a fair value method of accounting
for employee stock options and similar equity instruments. SFAS No. 123 allows
for the continued measurement of compensation cost for such plans using the
intrinsic value based method prescribed by APB Opinion No. 25, "Accounting for
Stock Issued to Employees" (APB No. 25), provided that pro forma results of
operations are disclosed for those options granted. The Company accounts for
stock options granted to employees and directors of the Company under the
intrinsic value method. Had the Company reported compensation costs as
determined by the fair value method of accounting for option grants to employees
and directors, net income and net income per common share would approximate the
following pro forma amounts:
6
Three Months Ended Six Months Ended
--------------------------------- ---------------------------------
June 30, 2004 June 30, 2003 June 30, 2004 June 30, 2003
------------- ------------- ------------- -------------
Net income:
As reported $ 18,522,504 $ 7,620,055 $ 38,305,722 $ 15,841,546
Pro forma $ 17,630,719 $ 7,620,055 $ 36,549,167 $ 15,841,546
Basic earnings per share:
As reported $ 0.25 $ 0.10 $ 0.51 $ 0.21
Pro forma $ 0.24 $ 0.10 $ 0.49 $ 0.21
Diluted earnings per share:
As reported $ 0.23 $ 0.10 $ 0.48 $ 0.20
Pro forma $ 0.22 $ 0.10 $ 0.46 $ 0.20
For purposes of pro forma disclosures, the estimated fair value of options is
amortized to expense over the options' vesting period. The weighted-average fair
value of each option granted is estimated on the date of grant using the Black
Scholes option pricing model with an assumed expected volatility of 25%. All
options have expected lives of 10 years.
2. OIL AND GAS PROPERTIES:
June 30, December 31,
2004 2003
------------- -------------
Developed Properties:
Acquisition, equipment, exploration,
drilling and environmental costs $ 306,386,349 $ 249,784,562
Less accumulated depletion, depreciation
and amortization (49,069,605) (38,495,605)
------------- -------------
257,316,744 211,288,957
Unproven Properties:
China 87,493,334 80,970,244
Acquisition and exploration costs 16,440,615 15,604,521
------------- -------------
$ 361,250,693 $ 307,863,722
============= =============
3. LONG-TERM DEBT:
June 30, December 31,
2004 2003
------------ ------------
Bank indebtedness $114,000,000 $ 99,000,000
Other long term obligations 7,819,922 5,120,213
------------ ------------
$121,819,922 $104,120,213
============ ============
The Company (through its subsidiary) participates in a long-term credit facility
with a group of banks led by Bank One N.A. The agreement specifies a maximum
loan amount of $500 million and an aggregate borrowing base of $315 million and
a commitment amount of $200 million at June 9, 2004. The commitment amount may
be increased up to the lesser of the borrowing base amount or $500 million at
any time at the request of the Company. Each bank shall have the right, but not
the obligation, to increase the amount of their commitment as requested by the
Company. In the event that the existing banks increase their commitment to an
amount less than the requested commitment amount, then it would be necessary to
bring additional banks into the facility. At June 30, 2004, the Company had $114
million outstanding and $86 million unused and available on the credit facility.
The credit facility matures on May 1, 2008. The note bears interest at either
the bank's prime rate plus a margin of one-quarter of one percent (0.25%) to
seven-eighths of one percent (0.875%) based on the percentage of available
credit drawn or at LIBOR plus a margin of one and one-quarter percent (1.25%) to
one and seven-eighths of one percent (1.875%) based on the percentage of
available credit drawn. For the purposes of calculating interest, the available
credit is equal to the borrowing base. An average annual commitment fee of 0.30%
to 0.50%, depending on the percentage of available credit drawn, is charged
quarterly for any unused portion of the commitment amount.
The borrowing base is subject to periodic (at least semi-annual) review and
re-determination by the banks and may be decreased or increased depending on a
number of factors, including the Company's proved reserves and the bank's
forecast of future oil and gas prices. If the borrowing base is reduced to an
amount less than the balance outstanding, the Company has sixty days from the
date of written notice of the reduction in the borrowing base to pay the
difference. Additionally, the Company is subject to quarterly reviews of
compliance with the covenants under the bank facility including minimum coverage
ratios relating to interest, working capital and advances to Sino-American
Energy Corporation. In the event of a default under the covenants, the Company
may not be able to access funds otherwise available under the facility. As of
June 30, 2004, the Company was in compliance with required ratios of the bank
facility.
The debt outstanding under the credit facility is secured by a majority of the
Company's proved domestic oil and gas properties.
4. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND
THE UNITED STATES:
In September 2003, the AcSB (Accounting Standards Board) released revised
transitional provisions for Stock-Based Compensation and Other Stock-Based
Payments, Section 3870, to provide the same alternative methods of transition as
is provided in the US for voluntary adoption of the fair value based method of
accounting. These provisions permit either retroactive (with or without
restatement) or prospective application of the recognition provisions to awards
not previously accounted for at fair value. Prospective application is only
available to enterprises that elect to apply the fair value based method of
accounting to that type of award for fiscal years beginning before January 1,
2004.
7
The AcSB has also amended Section 3870 to require that all transactions whereby
goods and services are received in exchange for stock-based compensation and
other payments result in expenses that should be recognized in financial
statements, and that this requirement would be applicable for financial periods
beginning on or after January 1, 2004. Section 3870 requires that share-based
transactions be measured on a fair value basis.
As described in Note 1, had the Company expensed the fair value of options
vested during the period, net income would have been reported as $17,630,719 for
the quarter ended June 30, 2004 and $36,549,167 for the six months ended June
30, 2004.
Recorded in other comprehensive loss in the equity section of the Company's
balance sheet is an offset of $6,800,695 to a liability that measures a future
effect of the fixed price to index price swap agreements that the Company
currently has in place. The Company has recorded this in compliance with FASB
No. 133 which addresses accounting impacts of derivative instruments.
The AcSB issued a new Accounting Guideline ("Guideline"), AcG-13, Hedging
Relationships, in December 2001 in connection with amendments to CICA Handbook
Section 1650, Foreign Currency Translation. The Guideline is applicable to
hedging relationships in effect in fiscal years beginning on or after July 1,
2003 (the AcSB changed the original effective date of January 1, 2002 in its
December 2001 meeting, and further deferred the effective date in its September
2002 meeting). The Guideline is not applicable to prior periods, but requires
the discontinuance of hedge accounting for hedging relationships established in
prior periods that do not meet the conditions for hedge accounting at the date
it is first applied.
The Guideline supplements some of the requirements on accounting for hedges of
foreign currency items in Section 1650, but is equally applicable to accounting
for hedges of other types of risk exposure. The Guideline deals with the
identification, documentation, designation and effectiveness of hedges and also
the discontinuance of hedge accounting, but does not specify hedge accounting
methods.
The Guideline is intended to improve the quality and consistency of hedge
accounting under Canadian GAAP. The Guideline incorporates certain features of
the U.S. hedge accounting standards as requirements. The AcSB has attempted to
avoid creating any additional GAAP differences, i.e., requirements that prevent
an entity from adopting a U.S. requirement. However, Canadian hedge accounting
remains inconsistent with U.S. GAAP in some fundamental ways.
5. RECENT ACCOUNTING PRONOUNCEMENTS:
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 requires the Company to record the fair value of an
asset retirement obligation as a liability in the period in which it incurs a
legal obligation associated with the retirement of tangible long-lived assets
that result from the acquisition, construction, development and/or normal use of
the assets. The Company has determined that the impact of adopting SFAS No. 143
is not material to its financial position or results of operations.
ITEM 2 - MANAGEMENT'S 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 segment, natural gas and oil
exploration and development with two geographical segments; the United States
and China.
The Company currently generates the majority of its revenue, earnings and cash
from the production and sales of natural gas and oil from its property in
southwestern Wyoming. The price of natural gas in the southwest Wyoming region
is a critical factor to the Company's business. The price of gas in southwest
Wyoming historically has been volatile. The average annual realizations for the
period 2001-2003 have ranged from $2.33 to $4.16 per Mcf. This volatility could
be very detrimental to the Company's financial performance. The Company seeks to
limit the impact of this volatility on its results by entering into derivative
and forward sales contracts for gas in southwest Wyoming. The average
realization for the Company's gas during the second quarter of 2004 was $4.73
per Mcf, basis Opal, Wyoming, including the effect of hedges. For the six-month
period ended June 30, 2004, the average realization for the Company's gas was
$4.84 per Mcf, basis Opal, Wyoming, including the effect of hedges. On July 18,
2004 the Company initiated production at the first two fields of the nine fields
discovered on its oil properties offshore Bohai Bay, China. The Company expects
to sell its first cargo of oil in late September, 2004. At that time, the price
of oil in east Asia will become critical to the Company. The Company expects
that its Chinese oil production will be priced based on the Duri Indonesian
crude oil price posting, the regional heavy oil marker price which, as of July
27, 2004, was approximately $33.21 per barrel. The Company has the right to
export and sell the crude at market prices.
The Company has grown its natural gas and oil production significantly over the
past three years and management believes it has the ability to continue growing
production by drilling already identified locations on its leases in Wyoming and
by bringing into production the already discovered oilfields in China. The
Company delivered 63% production growth on an Mcfe basis during the quarter
ended June 30, 2004 as compared to the same quarter in 2003 and 57% for the
six-month period ended June 30, 2004 compared to the same period in 2003.
Management expects to deliver additional production growth during the balance of
2004 to reach an anticipated annual production of 44 Bcfe in 2004, a 52% growth
in annual production over 2003 levels. This increase in production is expected
to be achieved by drilling and bringing into production additional wells in
Wyoming.
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 to the Company's cost centers. 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. The Company conducts operations in both the United
States and China. Separate cost centers are maintained for each country in which
the Company has operations. Substantially all of the oil and gas activities are
conducted jointly with others and, accordingly, the amounts in these financial
statements reflect only the Company's proportionate interest in such activities.
Inflation has not had a material impact on the Company's results of operations
and is not expected to have a material impact on the Company's results of
operations in the future.
8
RESULTS OF OPERATIONS
QUARTER ENDED JUNE 30, 2004 VS. QUARTER ENDED JUNE 30, 2003
During the quarter ended June 30, 2004, production increased 63% on an
equivalent basis to 9.6 Bcfe from 5.9 Bcfe for the same quarter in 2003
primarily because of the additional wells drilled and completed during 2003 and
the first half of 2004. Average realized price for natural gas and condensate
increased 20% on an equivalent basis to $4.80 per Mcfe during the quarter ended
June 30, 2004 from $3.99 per Mcfe for the same quarter in 2003 resulting in a
97% increase in revenues to $46.1 million.
Production costs increased 89% to $9.4 million primarily due to the 63% increase
in production and higher production taxes driven by the 97% increase in
revenues. Production taxes are calculated as a percentage of revenue, which
percentage increased slightly to 12% from 11% in the same quarter last year, due
primarily to the phasing out of certain tax benefits. On a unit of production
basis, production costs increased 16% to $0.98 per Mcfe. The increase in
production costs was attributable almost wholly to the increase in production
taxes arising from higher revenues.
Net income before income taxes increased 132% to $28.7 million and income tax
provision-deferred increased by 114% to $10.2 million at a rate of 35.5%. Net
income increased 143% to $18.5 million or $0.23 per diluted share.
SIX-MONTHS ENDED JUNE 30, 2004 VS. SIX-MONTHS ENDED JUNE 30, 2003
During the six-months ended June 30, 2004, production increased 57% on an
equivalent basis to 19.3 Bcfe from 12.3 Bcfe for the same six-months in 2003
primarily because of the additional wells drilled and completed during 2003 and
the increased drilling and completion during the first six-months of the year.
Average realized price for natural gas and condensate increased 25% on an
equivalent basis to $4.90 per Mcfe during the six-month period ended June 30,
2004 from $3.91 per Mcfe for the same period in 2003 resulting in a 97% increase
in revenues to $94.7 million.
Production costs increased 88% to $19.1 million primarily due to the 57%
increase in production and higher production taxes driven by the 97% increase in
revenues. Production taxes are calculated as a percentage of revenue, which
percentage increased slightly to 12% during the six-month period ended June 30,
2004 from 11% in the same six-months last year, due primarily to the phasing out
of certain tax benefits. On a unit of production basis, production costs
increased 20% to $0.99 per Mcfe . The increase in production costs was
attributable almost wholly to the increase in production taxes arising from
higher revenues.
Net income before income taxes increased 131% to $59.4 million and income tax
provision-deferred increased by 113% to $21.1 million at a rate of 35.5%. Net
income increased 142% to $38.3 million, or $0.48 per diluted share.
The discussion and analysis of the Company's financial condition and results of
operations is based upon consolidated financial statements, which have been
prepared in accordance with U.S. GAAP. In addition, application of generally
accepted accounting principles requires the use of estimates, judgments and
assumptions that affect the reported amounts of assets and liabilities as of the
date of the financial statements as well as the revenues and expenses reported
during the period. Changes in these estimates, judgments and assumptions will
occur as a result of future events, and, accordingly, actual results could
differ from amounts estimated.
LIQUIDITY AND CAPITAL RESOURCES
During the six month period ended June 30, 2004, the Company relied on cash
provided by operations and borrowings under its senior credit facility to
finance its capital expenditures. The Company participated in the drilling of 35
wells in Wyoming and continued to participate in the development process in the
China blocks including the ongoing drilling of development wells. For the
six-month period ended June 30, 2004 net capital expenditures were $63.7
million. At June 30, 2004, the Company reported a cash position of $9.2 million
compared to $0.7 million at June 30, 2003. Working capital surplus at June 30,
2004 was $2.1 million as compared to $(15.3) million at June 30, 2003. As of
June 30, 2004, the Company had incurred bank indebtedness of $114.0 million and
other long-term obligations of $7.8 million comprised of items payable in more
than one year, primarily related to production taxes.
The Company's positive cash provided by operating activities, along with the
availability under the senior credit facility, are projected to be sufficient to
fund the Company's budgeted capital expenditures for 2004, which are currently
projected to be $190.0 million. Of the $190.0 million budget, the Company plans
to spend approximately $162.0 million of its 2004 budget in Wyoming and
approximately $25.0 million in China with the balance allocated to evaluating
other areas. To date the Company has spent $63.7 million of the $190.0 million
capital budget. Of the $162.0 million for Wyoming, the Company plans to drill or
participate in an estimated 80 gross wells in 2004, of which approximately 40%
will be for exploration wells and the remaining will be for development wells.
Of the $25.0 million budgeted for China, approximately 12% will be for
exploratory/appraisal activity and the balance will be for development activity.
The Company currently has no budget for acquisitions in 2004.
The Company (through its subsidiary) participates in a long-term credit facility
with a group of banks led by Bank One N.A. The agreement specifies a maximum
loan amount of $500 million and an aggregate borrowing base of $315 million and
a commitment amount of $200 million at June 9, 2004. The commitment amount may
be increased up to the lesser of the borrowing base amount or $500 million at
any time at the request of the Company. Each bank shall have the right, but not
the obligation, to increase the amount of their commitment as requested by the
Company. In the event that the existing banks increase their commitment to an
amount less than the requested commitment amount, then it would be necessary to
bring additional banks into the facility. At June 30, 2004, the Company had $114
million outstanding and $86 million unused and available on the credit facility.
The credit facility matures on May 1, 2008. The note bears interest at either
the bank's prime rate plus a margin of one-quarter of one percent (0.25%) to
seven-eighths of one percent (0.875%) based on the percentage of available
credit drawn or at LIBOR plus a margin of one and one-quarter percent (1.25%) to
one and seven-eighths of one percent (1.875%) based on the percentage of
available credit drawn. For the purposes of calculating interest, the available
credit is equal to the borrowing base. An average annual commitment fee of 0.30%
to 0.50%, depending on the percentage of available credit drawn, is charged
quarterly for any unused portion of the commitment amount.
The borrowing base is subject to periodic (at least semi-annual) review and
re-determination by the banks and may be decreased or increased depending on a
number of factors, including the Company's proved reserves and the banks
forecast of future oil and gas prices. If
9
the borrowing base is reduced to an amount less than the balance outstanding,
the Company has sixty days from the date of written notice of the reduction in
the borrowing base to pay the difference. Additionally, the Company is subject
to quarterly reviews of compliance with the covenants under the bank facility
including minimum coverage ratios relating to interest, working capital and
advances to Sino-American Energy Corporation. In the event of a default under
the covenants, the Company may not be able to access funds otherwise available
under the facility. As of June 30, 2004, the Company was in compliance with
required ratios of the bank facility.
The debt outstanding under the credit facility is secured by a majority of the
Company's proved domestic oil and gas properties.
During the six-months ended June 30, 2004, net cash provided by operating
activities was $66.3 million as compared to $32.8 million for the six-months
ended June 30, 2003. The increase in cash provided by operating activities was
primarily attributable to the increase in earnings and deferred income taxes.
During the six-months ended June 30, 2004, cash used in investing activities was
$74.8 million as compared to $20 million for the six-months ended June 30, 2003.
The change is primarily attributable to increased activity for drilling and
completion activity in Wyoming and China. Of the $74.8 million used in investing
activities, $63.7 million has been used for drilling and completion activities
in 2004, while $10.5 million accounts for expenditures for the prior year's
activity.
During the six-months ended June 30, 2004, cash provided by (used in) financing
activities was $15.7 million as compared to $(13.5) million for the six-months
ended June 30, 2003. The change is primarily attributable to increased
borrowings under the senior credit facility.
OFF-BALANCE SHEET ARRANGEMENTS
The Company did not have any off-balance sheet arrangements as of June 30, 2004.
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 Management's 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
Company's 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 Company's planned future
capital program.
Other risks and uncertainties include, but are not limited to, fluctuations in
the price the Company receives for oil and gas production, reductions in the
quantity of oil and gas sold due to increased industry-wide demand and/or
curtailments in production from specific properties due to mechanical, marketing
or other problems, operating and capital expenditures that are either
significantly higher or lower than anticipated because the actual cost of
identified projects varied from original estimates and/or from the number of
exploration and development opportunities being greater or fewer than currently
anticipated and increased financing costs due to a significant increase in
interest rates. See the Company's annual report on Form 10-K for the year ended
December 31, 2003 for additional risks related to the Company's business.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's major market risk exposure is in the pricing applicable to its gas
and oil production. Realized pricing is primarily driven by the prevailing price
for crude oil and spot prices applicable to the Company's U.S. natural gas
production. Historically, prices received for gas production have been volatile
and unpredictable. Pricing volatility is expected to continue. Gas price
realizations averaged $4.84 per Mcf during the six months ended June 30, 2004.
This average price includes the effects of hedging and gas balancing between
working interest owners.
The Company periodically enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and natural gas
price volatility. The Company primarily utilizes fixed price physical contracts
as well as price swaps, which are placed with major financial institutions or
with counter-parties of high credit quality that it believes are minimal credit
risks. The oil and natural gas reference prices of these commodity derivatives
contracts are based upon crude oil and natural gas futures, which have a high
degree of historical correlation with actual prices the Company receives. Under
SFAS No. 133 all derivative instruments are recorded on the balance sheet at
fair value. Changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For qualifying cash
flow hedges, the gain or loss on the derivative is deferred in accumulated other
comprehensive income (loss) to the extent the hedge is effective. For qualifying
fair value hedges, the gain or loss on the derivative is offset by related
results of the hedged item in the income statement. Gains and losses on hedging
instruments included in accumulated other comprehensive income (loss) are
reclassified to oil and natural gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not qualify for hedge
accounting treatment are recorded as derivative assets and liabilities at market
value in the consolidated balance sheet, and the associated unrealized gains and
losses are recorded as current expense or income in the consolidated statement
of operations. The Company currently does not have any derivative contracts in
place that do not qualify as a cash flow hedge.
During the first six months of 2004, the total impact of the Company's price
swaps was a reduction in gas revenues of $3.3 million. The effect of fixed price
physical contracts is not included in this amount. The Company does not
currently hedge its oil production.
At June 30, 2004, the Company had the following open derivative contracts to
manage price risk on a portion of its natural gas production whereby the Company
receives the fixed price and pays the variable price (all prices southwest
Wyoming basis). (The Company's gas contains approximately 1.06 MMBtu per Mcf
upon delivery at the sales point.)
10
DERIVATIVE CONTRACTS
Contract Volume - Average
Type Period MBTU / day Price / MMbtu
----- -------------- ---------- -------------
Swap Calendar 2004 20,000 $ 4.09
Swap April-Oct 2004 5,000 $ 4.76
Swap Calendar 2005 10,000 $ 4.42
The Company also utilizes fixed price forward gas sales contracts at southwest
Wyoming delivery points to hedge its commodity exposure. In addition to the
derivative contracts discussed above, the Company had the following fixed price
physical delivery contracts in place on behalf of its interest and those of
other parties at June 30, 2004. (The Company's approximate average net interest
in physical gas sales is 80%.)
FIXED PRICE FORWARD SALES CONTRACTS
Contract Volume - Average
Period MMBTU / day Price / MMbtu
-------------- ----------- --------------
July-Oct 2004 25,000 $ 4.72
July-Dec 2004 30,000 $ 4.10
Calendar 2005 45,000 $ 4.51
Calendar 2006 15,000 $ 4.07
The above derivative and forward gas sales contracts represent approximately 41%
of the Company's currently forecasted gas production for the balance of 2004,
28% for calendar year 2005 and 5% for calendar year 2006.
ITEM 4 - CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures. The Company's management,
including the Company's principal executive officer and principal financial
officer, has evaluated the effectiveness of the Company's disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) under the
Securities Exchange Act of 1934) as of the end of the period covered by this
Quarterly Report on Form 10-Q. Based upon that evaluation, the Company's
principal executive officer and principal financial officer have concluded that
the disclosure controls and procedures were effective to ensure that information
required to be disclosed by the Company in reports that it files or submits
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the rules and forms of the
Securities and Exchange Commission as of the end of the period covered by this
Quarterly Report on Form 10-Q.
(b) Changes in Internal Controls. There were no changes in the Company's
internal control over financial reporting that occurred during the Company's
last fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the Company's internal control over financial reporting.
PART 2 - 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 Company's financial position, or results of operations.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
The Company held its annual meeting on May 20, 2004. At the annual meeting the
entire board of directors of the Company was elected. The votes cast for each of
the directors proposed by the Company's definitive proxy statement on Schedule
14A was as follows:
Michael D. Watford - 60,294,505 voted in favor, 244,172 voted against and 1500
votes withheld.
W. Charles Helton - 60,326,323 voted in favor, 212,354 voted against and 1500
votes withheld.
James E. Nielson - 60,329,338 voted in favor, 209,339 voted against and 1500
votes withheld.
James C. Roe - 60,276,031 voted in favor, 262,646 voted against and 1500 votes
withheld.
Robert E. Rigney - 60,219,456 voted in favor, 319,221 voted against and 1500
votes withheld.
The shareholders of the Company also approved the re-appointment of KPMG, LLP as
the Company's independent auditors for 2003. There were 60,417,975 votes in
favor of approval of the re-appointment of KPMG, LLP as the Company's auditors,
0 votes against and 122,202 votes withheld.
A total of 60,657,257 shares were voted by 426 shareholders, representing 81% of
the Company's outstanding shares.
11
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
3.1 Articles of Incorporation of Ultra Petroleum Corp. - (incorporated by
reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 2001)
3.2 By-Laws of Ultra Petroleum Corp. - (incorporated by reference to
Exhibit 3.2 of the Company's Quarterly Report on Form 10-Q for the period
ended June 30, 2001)
4.1 Specimen Common Share Certificate - (incorporated by reference to
Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q for the period
ended June 30, 2001)
10.1 Second Amended and Restated Credit Agreement dated June 9, 2004 among
Ultra Resources, Inc., Bank One, NA, Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank, Compass Bank, Bank of Scotland
and Fleet National Bank.
31.1 Certification Pursuant to Rule 13a-14(a)
31.2 Certification Pursuant to Rule 13a-14(a)
32.1 Certification Pursuant to Rule 13a-14(b)
32.2 Certification Pursuant to Rule 13a-14(b)
(b) Reports on Form 8-K
Current Report on Form 8-K filed on April 29, 2004 reporting earnings and
other information for the period ended March 31, 2004 under Item 12,
Results of Operations and Financial Condition.
Current Report on Form 8-K filed on April 28, 2004 announcing an earnings
conference call for the period ended March 31, 2004 under Item 12 Results
of Operations and Financial Condition.
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.
Date July 30, 2004 By: /s/ Michael D. Watford
-----------------------------------
Name: Michael D. Watford
Title: Chief Executive Officer
By: /s/ F. Fox Benton III
-----------------------------------
Name: F. Fox Benton III
Title: Chief Financial Officer
12