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, 2003
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, 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 August 4th, 2003 was 74,227,668
1
PART 1 - FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Expressed in U.S. Dollars)
For the Three Months Ended For the Six Months Ended
June 30, June 30,
------------------------------ ------------------------------
2003 2002 2003 2002
------------ ----------- ------------ -------------
Revenues
Natural gas sales $ 22,001,224 $ 7,462,282 $ 45,123,812 $ 15,862,228
Oil sales 1,464,430 681,105 3,012,936 1,387,478
------------ ----------- ------------ -------------
23,465,654 8,143,387 48,136,748 17,249,706
Expenses
Production expenses and taxes 4,973,661 2,092,197 10,175,404 4,581,129
Depletion and depreciation 3,451,894 1,745,291 7,057,740 3,853,588
General and administrative 1,503,772 1,210,952 2,741,475 2,059,263
Stock compensation 405,720 425,280 1,018,220 796,165
------------ ----------- ------------ -------------
10,335,047 5,473,720 20,992,839 11,290,145
Operating income 13,130,607 2,669,667 27,143,909 5,959,561
Other income :
Interest expense (750,834) (692,156) (1,404,434) (1,206,217)
Interest income 11,191 5,346 19,768 12,336
------------ ----------- ------------ -------------
(739,643) (686,810) (1,384,666) (1,193,881)
Income for the period, before income tax provision 12,390,964 1,982,857 25,759,243 4,765,680
Income tax provision - deferred 4,770,909 675,989 9,917,697 1,747,376
Net income for the period 7,620,055 1,306,868 15,841,546 3,018,304
------------ ----------- ------------ -------------
Retained earnings, beginning of period 19,037,368 4,445,792 10,815,877 2,734,356
------------ ----------- ------------ -------------
Retained earnings, end of period $ 26,657,423 $ 5,752,660 $ 26,657,423 $ 5,752,660
============ =========== ============ =============
Income per common share - basic $ 0.10 $ 0.02 $ 0.21 $ 0.04
============ =========== ============ =============
Income per common share - fully diluted $ 0.10 $ 0.02 $ 0.20 $ 0.04
============ =========== ============ =============
Weighted average common shares outstanding - basic 74,172,652 73,771,411 74,115,066 73,634,564
============ =========== ============ =============
Weighted average common shares outstanding - fully
diluted 78,303,218 77,648,635 78,121,136 77,523,856
============ =========== ============ =============
2
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Expressed in U.S. Dollars)
Six Months Ended
June 30,
------------ ------------
2003 2002
------------ ------------
Cash provided by (used in):
Operating activities:
Net income for the period $ 15,841,546 $ 3,018,304
Add (deduct)
Items not involving cash:
Depletion and depreciation 7,057,740 3,853,588
Deferred income taxes 9,917,697 1,747,376
Stock compensation 1,018,220 884,765
Net changes in non-cash working capital:
Restricted cash (726) (1,299)
Accounts receivable (564,995) 806,481
Prepaid expenses and other current assets (2,233,743) 937,041
Accounts payable and accrued liabilities 9,615,237 (4,868,729)
Other long-term obligations 2,242,178 (50,000)
------------ ------------
42,893,154 6,327,527
Investing activities:
Oil and gas property expenditures (29,596,381) (23,527,232)
Purchase of capital assets (533,884) (590,407)
------------ ------------
(30,130,265) (24,117,639)
Financing activities:
Long-term debt (14,000,000) 18,000,000
Repurchased shares - (1,133,750)
Proceeds from exercise of options 474,947 893,280
------------ ------------
(13,525,053) 17,759,530
Increase in cash during the period (762,164) (30,582)
Cash and cash equivalents, beginning of period 1,417,711 1,379,462
------------ ------------
Cash and cash equivalents, end of period $ 655,547 $ 1,348,880
============ ============
3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Expressed in U.S. Dollars)
June 30, December 31,
2003 2002
------------- -------------
Assets
Current assets
Cash and cash equivalents $ 655,547 $ 1,417,711
Restricted cash 210,032 209,306
Accounts receivable 11,963,478 11,398,483
Prepaid expenses and other current assets 2,708,022 474,279
------------- -------------
15,537,079 13,499,779
Oil and gas properties, using the full cost
method of accounting 230,388,300 207,362,408
Capital assets 1,300,843 1,011,699
------------- -------------
Total assets $ 247,226,222 $ 221,873,886
============= =============
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities $ 31,126,279 $ 17,914,860
Long-term debt 72,000,000 86,000,000
Deferred income taxes 18,314,596 10,033,174
Other long-term obligations 6,100,988 3,858,810
Shareholders' equity
Share capital 96,834,371 95,098,690
Treasury stock (1,193,650) (1,193,650)
Other comprehensive loss (2,613,785) (653,875)
Retained earnings 26,657,423 10,815,877
------------- -------------
119,684,359 104,067,042
------------- -------------
Total liabilities and shareholders' equity $ 247,226,222 $ 221,873,886
============= =============
4
ULTRA PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in U.S. dollars unless otherwise noted)
Three months ended June 30, 2003 and 2002
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 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, 2002, are unaudited and were prepared from the Company's records.
Balance sheet data as of December 31, 2002 was derived from the Company's
audited financial statements, but do 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 statements on a basis consistent with the Company's
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 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
US GAAP.
(c) Cash and cash equivalents:
We consider 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.
5
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.
(g) Hedging 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 a financial institution 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 the 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 shares 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, June 30, June 30, June 30,
2003 2002 2003 2002
----------- ------------- ------------- -----------
Net income $ 7,620,055 $ 1,306,868 $ 15,841,546 $ 3,018,304
=========== ============= ============= ===========
Weighted average of common shares
outstanding during the period 74,172,652 73,771,411 74,115,066 73,634,564
Effect of dilutive instruments 4,130,566 3,877,224 4,006,070 3,889,292
----------- ------------- ------------- -----------
Weighted average common shares outstanding
during the period including the effects of
dilutive instruments 78,303,218 77,648,635 78,121,136 77,523,856
=========== ============= ============= ===========
Basic earnings per share $ 0.10 $ 0.02 $ 0.21 $ 0.04
=========== ============= ============= ===========
Diluted earnings per share $ 0.10 $ 0.02 $ 0.20 $ 0.04
=========== ============= ============= ===========
(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.
6
2. OIL AND GAS PROPERTIES:
June 30, December 31,
2003 2002
------------ ---------------
Developed Properties:
Acquisition, equipment, exploration
drilling and environmental costs $175,588,180 $150,986,843
Less accumulated depletion, depreciation and
amortization (29,629,605) (22,816,605)
------------ ------------
145,958,575 128,170,238
Unproven Properties:
China 69,701,321 64,873,186
Acquisition and exploration costs 14,728,404 14,318,984
------------ ------------
$230,388,300 $207,362,408
============ ============
3. LONG-TERM DEBT:
June 30, December 31,
2003 2002
------------ ------------
Bank indebtedness $ 72,000,000 $ 86,000,000
Short term obligations to be refinanced - 3,858,810
============ ============
$ 72,000,000 $ 89,858,810
============ ============
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 $250.0 million and an aggregate borrowing base of $155.0 million
at May 14, 2003. At June 30, 2003, the Company had $72.0 million outstanding and
$83.0 million unused and available on the credit facility.
The credit facility matures on March 1, 2006. The note bears interest at either
the bank's prime rate plus a margin of one-half of one percent (0.50%) to one
and one-quarter percent (1.25%) based on the percentage of available credit
drawn or at LIBOR plus a margin of one and one-half percent (1.5%) to two and
one-quarter percent (2.25%) based on the percentage of available credit drawn.
An average annual commitment fee of 0.375% is charged quarterly for any unused
portion of the credit line.
The borrowing base is subject to periodic (at least semi-annual) review and
re-determination by the bank 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 60 days 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, 2003, the Company was in compliance with the covenants and required
ratios.
The Company has secured this debt with a majority of its proved domestic oil and
gas properties.
4. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND
THE UNITED STATES:
Currently under Canadian generally accepted accounting principles ("Canadian
GAAP"), there is not a provision in place to expense stock-based compensation as
with Financial Accounting Standards Board ("FASB") Statement No. 123 "Accounting
for Stock-Based Compensation". However, there was an exposure draft issued in
December 2002 that would essentially harmonize their accounting standards to US
GAAP. The proposed effective date for implementing Stock-Based Compensation and
Other Stock-Based Payments, Section 3870, is January 1, 2004.
Recorded in other comprehensive income in the equity section of the Company's
balance sheet is an offset 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 addressing
accounting impacts of derivative instruments. Currently under Canadian GAAP the
future effects of derivative instruments are recorded through revenue in the
period in which the production is sold. The total future value of the swap is
not captured as an asset or liability, and the term Other Comprehensive Income,
is not recognized in Canada. In 2002, the Canadian Accounting Standards Board
issued a draft proposal to put in place Canadian standards for the treatment of
derivative instruments which would be in harmony with U.S. standards on
financial instruments. Canadian enterprises could then choose to apply
accounting policies and practices that are in accordance with both U.S. and
Canadian GAAP.
5. RECENT ACCOUNTING PRONOUNCEMENTS:
The Company has been made aware of an issue that has arisen in the industry
regarding the application of certain provisions of SFAS No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," to
companies in the extractive industries, including oil and gas companies. The
FASB and the SEC are considering whether the provisions of SFAS No. 141 and SFAS
No. 142 require registrants to classify costs associated with mineral rights,
including both proved and unproved lease acquisition costs, as intangible assets
in the balance sheet, apart from other capitalized oil and gas property costs,
and provide specific footnote disclosures.
7
Historically, the Company has included oil and gas lease acquisition costs as a
component of oil and gas properties. In the event it is determined that costs
associated with mineral rights are required to be classified as intangible
assets, a substantial portion of the Company's oil and gas property acquisition
costs since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be
separately classified on its balance sheets as intangible assets. However, the
Company's results of operations would not be affected since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with full cost accounting rules. Further, the Company does not believe the
classification of oil and gas lease acquisition costs as intangible assets would
have any impact on the Company's compliance with covenants under its debt
agreements.
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 adopted SFAS No. 143 on January 1, 2003. Based on
current estimates, the Company would record asset retirement obligations (using
a 10% discount rate) and a cumulative effect of change in accounting principle,
related to the depreciation and accretion expense that would have been recorded
had the fair value of the asset retirement obligation, and corresponding
increase in the carrying amount of the related long-lived asset been determined
in prior years. The Company has determined that the impact of adopting SFAS No.
143 is not material to its financial position or results of operations.
The Company adopted the disclosure provisions of SFAS No. 148, Accounting for
Stock-Based Compensation-Transition and Disclosure" effective January 1, 2003.
SFAS No. 148 amended FASB Statement No. 123, "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair-value based method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the disclosure requirements of
Statement No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. The
provision of SFAS No. 148 has no material impact on the Company, as it does not
plan to adopt the fair-value method of accounting for stock options at the
current time. For the period ended June 30, 2003, the pro-forma net income, had
the Company adopted the provisions of Statement No. 123 equals net income.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
QUARTER ENDED JUNE 30, 2003 VS. QUARTER ENDED JUNE 30, 2002
OPERATING REVENUES
Oil and gas revenues increased to $23,465,654 for the quarter ended June 30,
2003 from $8,143,387 for the same period in 2002. This increase was attributable
to an increase in production and prices received for that production. During
this quarter, the Company's gas production increased 88% to 5.6 Bcf, up from 3.0
Bcf, while condensate increased to 47,000 barrels from 27,000 barrels for the
same period in 2002. During the quarter ended June 30, 2003 the average product
prices for gas and condensate were $3.93 per Mcf and $30.84 per barrel,
respectively, compared to $2.52 per Mcf and $25.58 per barrel for the same
period in 2002.
PRODUCTION EXPENSES AND TAXES
During the quarter ended June 30, 2003 production expenses and taxes increased
to $4,973,661 from $2,092,197 for the quarter ended June 30, 2002. Direct lease
operating expenses increased to $667,134 for the quarter ended June 30, 2003
from $418,277 for the same period in 2002. On a per unit of production basis,
these costs decreased to $.11 per Mcfe in June 2003, as compared to $.13 per
Mcfe in June 2002. Production taxes for the second quarter 2003 were $2,603,589,
compared to $783,452 in second quarter 2002 or $.44 per Mcfe in second quarter
2003, compared to $.25 per Mcfe in second quarter 2002. Production taxes are
calculated based on a percentage of revenue from production, therefore higher
realized prices and production contributed to the increase. Gathering fees for
the quarter ended June 30, 2003 increased to $1,702,938 from $890,468 for the
same period in 2002 based on higher production levels. On a per Mcfe basis the
rate remained a flat $.29.
DEPLETION AND DEPRECIATION
Depletion, depreciation and amortization expenses ("DD&A") were $3,451,894
during the quarter ended June 30, 2003 compared to $1,745,291 for the same
period in 2002. DD&A increased to $0.59 per Mcfe from $0.56 per Mcfe. This
increase is primarily attributable to the timing differences in which costs for
wells that were not classified as proved at year-end have been added to the cost
pool while the new reserves related to those wells have not been added to the
reserve estimates used to calculate the units of production depletion rate.
GENERAL AND ADMINISTRATIVE
General and administrative expenses increased to $1,503,772 during the quarter
ended June 30, 2003 from $1,210,952 for the same period in 2002. The increase
was attributable to legal, professional and compensation expenses, including
accrued incentive compensation, that coincide with the Company's increased
activity in both Wyoming and China.
INTEREST
Interest expense for the period increased to $750,834 in second quarter 2003
from $692,156 in second quarter 2002. This increase was attributable to the
increase in borrowings under the senior credit facility, partially offset by
lower overall interest rates.
INCOME TAXES
The Company recorded deferred income tax expense of $4,770,909 at an effective
rate of 38.5% for the quarter ended June 30, 2003, compared to $675,989 at an
effective rate of 34% for the quarter ended June 30, 2002. Although the Company
is not expected to pay material cash taxes in 2003, in accordance with FAS No.
109 and specifically, the guidance concerning intraperiod tax allocations, the
Company is required to recognize
8
tax expense evenly throughout the year. In the prior year, income tax expense,
as calculated at the statutory rate, was partially offset by recognition of
deferred tax assets for which a valuation allowance had previously been
provided.
SIX MONTHS ENDED JUNE 30, 2003 VS. SIX MONTHS ENDED JUNE 30, 2002
OPERATING REVENUES
Oil and gas revenues increased to $48,136,748 for the six months ended June 30,
2003 from $17,249,706 for the same period in 2002. This increase was
attributable to an increase in both production and in prices received for that
production. During the first half of this year, the Company's production
increased by 73% on an Mcf equivalent basis, to 11.6 Bcf of gas, and 100,000
barrels of condensate, up from 6.7 Bcf of gas and 60,000 barrels of condensate
for the same six months in 2002. During the six months ended June 30, 2003 the
average product prices for gas and condensate were $3.86 per Mcf and $29.90 per
barrel, respectively, compared to $2.36 per Mcf and $22.85 per barrel for the
same period in 2002.
PRODUCTION EXPENSES AND TAXES
During the six months ended June 30, 2003 production expenses and taxes
increased to $10,175,404 from $4,581,129 for the six months ended June 30, 2002.
Direct lease operating expenses increased to $1,612,420 for the six months ended
June 30, 2003 from $905,144 for the same period in 2002. On a per unit of
production basis, these costs remained a constant $.13 per Mcfe in a six month
period to six month period comparison. Production taxes for the first half of
2003 were $5,266,810, compared to $1,719,039 in the first six months of 2002 or
$.43 per Mcfe at June 2003, compared to $.24 per Mcfe at June 2002. Production
taxes are calculated based on a percentage of revenue from production, therefore
both increased production and realized prices contributed to the increase.
Gathering fees for the six months ended June 30, 2003 increased to $3,296,174
from $1,956,946 for the same period in 2002, primarily attributable to higher
production volumes.
DEPLETION AND DEPRECIATION
DD&A increased to $7,057,740 during the six months ended June 30, 2003 compared
to $3,853,588 for the same period in 2002. On a per unit basis, DD&A increased
to $.57 per Mcfe, from $.54 per Mcfe in 2002. This increase is primarily
attributable to the timing differences in which costs for wells that were not
classified as proved at year-end have been added to the cost pool while the new
reserves related to those wells have not been added to the reserve estimates
used to calculate the units of production depletion rate.
GENERAL AND ADMINISTRATIVE
General and administrative expenses totaled $2,741,475 during the six months
ended June 30, 2003 as compared to $2,059,263 for the same period in 2002. The
increase was attributable to legal, professional and compensation expenses
including accrued incentive compensation that coincide with the Company's
increased activity in both Wyoming and China.
INTEREST
Interest expense for the period increased to $1,404,434 during the six months
ending June 30, 2003 compared to $1,206,217 for the same period in 2002. This
increase was attributable to the increase in borrowings under the senior credit
facility.
INCOME TAXES
The Company recorded deferred income tax expense of $9,917,697 at an effective
rate of 38.5% for the six months ended June 30, 2003, compared to $1,747,376 at
an effective rate of 37% for the six months ended June 30, 2002. Although the
Company is not expected to pay material cash taxes in 2003, in accordance with
FASB No. 109 and specifically, the guidance concerning intraperiod tax
allocations, the Company is required to recognize tax expense evenly throughout
the year. In the prior year, income tax expense, as calculated at the statutory
rate, was offset by recognition of deferred tax assets for which a valuation
allowance had previously been provided.
LIQUIDITY AND CAPITAL RESOURCES
During the six month period ended June 30, 2003, the Company relied on cash
provided by operations to finance its capital expenditures. The Company
participated in the drilling of 24 wells in Wyoming, and also had continued
participation in the development process in the China blocks. For the six-month
period ended June 30, 2003 net capital expenditures were $30.0 million. At June
30, 2003, the Company reported a cash position of $656,000 compared to $1.3
million at June 30, 2002. Working capital deficit at June 30, 2003 was $(15.6)
million as compared to $(9.0) million at June 30, 2002. As of June 30, 2003, the
Company had incurred bank indebtedness of $72.0 million and other long-term debt
of $6.1 million comprised of items payable in more than one year.
The positive cash provided by operating activities that the Company continues to
produce, along with the availability under the senior credit facility, are
projected to be sufficient to fund the Company's budgeted capital expenditures
for 2003, which are currently projected to be $110.0 million. Of the $110.0
million budget, the Company plans to spend approximately $90.0 million of its
2003 budget in Wyoming and approximately $20.0 million in China. Of the $90.0
million for Wyoming, the Company plans to drill or participate in an estimated
57 gross wells in 2003, of which approximately 40% will be for exploration wells
and the remaining will be for development wells. Of the $20.0 million budgeted
for China, approximately 50% will be for exploratory/appraisal activity and the
balance will be for development activity. The Company currently has no budget
for acquisitions in 2003.
As of May 14, 2003, the revolving senior credit facility provides for a $250.0
million revolving credit line with a current borrowing base of $155.0 million.
The credit facility matures on March 1, 2006. The notes bear interest at either
Bank One's prime rate plus a margin of one-half of one percent (0.50%) to one
and one-quarter percent (1.25%) based on the percentage of available credit
drawn or at LIBOR plus a margin of one and one-half percent (1.50%) to two and
one-quarter percent (2.25%) based on the percentage of available credit drawn.
An average annual commitment fee of 0.375% is charged quarterly for any unused
portion of the credit line. The borrowing base is subject to periodic (at least
semi-annual) review and re-determination by the banks and may be increased or
decreased depending on a number of factors including the Company's proved
reserves and the bank's forecast of future oil and gas prices. Additionally, the
Company is subject to quarterly reviews of compliance with
9
the covenants under the bank facility including minimum coverage ratios relating
to interest, working capital and advances to Sino-American Energy. In the event
of a default under the covenants, the Company may not be able to access funds
otherwise available under the facility and may, in certain circumstances,
including reduction in borrowing base, be required to repay the credit
facilities. The notes are collateralized by a majority of the Company's proved
domestic oil and gas properties. At June 30, 2003, the Company had $72.0 million
of outstanding borrowings under this credit facility, with a current average
interest rate of approximately 3%. The Company was in compliance with all loan
covenants at June 30, 2003.
During the six-months ended June 30, 2003, net cash provided by operating
activities was $43.0 million as compared to $6.3 million for the six-months
ended June 30, 2002. The increase in cash provided by operating activities was
attributable to the increase in earnings.
During the six-months ended June 30, 2003, cash used in investing activities was
$30.1 million as compared to $24.1 million for the six-months ended June 30,
2002. The change is primarily attributable to increased activity for drilling
and completion activity in Wyoming.
During the six-months ended June 30, 2003, cash provided by financing activities
was $(13.5) million as compared to $17.8 million for the six-months ended June
30, 2002. The change is primarily attributable to paying down debt under the
senior credit facility.
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, 2002 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 $3.86 per Mcf during the six months ended June 30, 2003.
This average wellhead price includes the effects of hedging and gas balancing
between working interest owners.
The Company periodically enters into various hedging arrangements for its
natural gas production. During the first six months of 2003, the Company paid
$1,717,475 to counterparties to settle its hedges related to volumes produced
during the period. The amount was netted from revenues on the Consolidated
Statements of Income and reduced the reported price for gas during the period.
In the first half of 2003, the Company participated in swaps covering an
additional 10,000 MMBtu or approximately 9 MMcf of gas per day for the period
from April 1, 2003 to October 31, 2003 at a price of $3.75 per MMBtu or
approximately $3.95 per Mcf (pricing referenced to Opal), plus an additional
5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a
price of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to
Opal). Additionally, the Company entered into a fixed price sale for 5,000 MMBtu
or approximately 3.8 MMcf of gas per day for calendar 2004 at a price of $4.27
per MMBtu or approximately $4.52 per Mcf (pricing referenced to Opal).
The table below summarizes the hedges in place at June 30, 2003:
Daily Volume Price / MMBtu at
Type Period MMBTU OPAL WY
---- ------ ----- -------
Fixed Price Sale Calendar 2003 5,000 $ 3.06
Swap Calendar 2003 5,000 $3.005
Swap Calendar 2003 5,000 $ 3.27
Swap April-Oct 2003 10,000 $ 3.75
Swap April-Oct 2003 5,000 $ 4.25
Fixed Price Sale Calendar 2004 5,000 $ 4.27
These hedges represent approximately 45% of the Company's forecasted production
for the period from April 1, 2003 to October 31, 2003, and approximately 30% of
the Company's forecasted production for calendar 2003, and approximately
4% of the Company's forecasted production for calendar 2004.
ITEM 4 - 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 15d-15(e)
under the Securities Exchange Act of 1934) as of
10
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 as of the end of the period covered by this Quarterly Report on
Form 10-Q.
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
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 June 5, 2003. 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 - 37,979,568 voted in favor, 5,100 voted against and 652
votes withheld.
W. Charles Helton - 37,149,143 voted in favor, 835,525 voted against and 652
votes withheld.
James C. Roe - 37,147,061 voted in favor, 837,407 voted against and 852 votes
withheld.
James E. Nielson - 37,980,386 voted in favor, 4,082 voted against and 852 votes
withheld.
Robert E. Rigney - 37,147,061 voted in favor, 837,407 voted against and 852
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 37,979,228 votes in
favor of approval of the re-appointment of KPMG, LLP as the Company's auditors,
2,324 votes against and 3,768 votes withheld.
A total of 38,000,320 shares were voted by 220 shareholders, representing 51% of
the Company's outstanding shares.
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 Second Amendment to First Amended and Restated Credit Agreement dated
May 14, 2003 among Ultra Resources, Inc., Bank One N.A., Union Bank
of California, N.A., Guaranty Bank, FSB, Hibernia National Bank,
Compass Bank and Bank of Scotland
10.2 First Amendment to First Amended and Restated Credit Agreement dated
November 4, 2002 among Ultra Resources, Inc., Bank One N.A., Union
Bank of California, N.A., Guaranty Bank, FSB, Hibernia National Bank
and Compass Bank (incorporated by reference to Exhibit 10.1 to the
Company's annual report on Form 10-K for the period ended December
31, 2002)
10.3 First Amended and Restated Credit Agreement dated March 1, 2002 among
Ultra Resources, Inc., Bank One N.A., Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank and Compass Bank
(incorporated by reference to Exhibit 10.1 to the Company's annual
report on Form 10-K for the period ended December 31, 2001)
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
32.2 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
(b) Reports on Form 8-K
Press release dated August 1, 2003 announcing Earnings Release Conference
Call.
11
Press release dated August 4, 2003 announcing Second Quarter Earnings.
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 August 11, 2002 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
EXHIBIT INDEX
Exhibit
Number Description
------ -----------
10.1 Second Amendment to First Amended and Restated Credit Agreement dated
May 14, 2003 among Ultra Resources, Inc., Bank One N.A., Union Bank
of California, N.A., Guaranty Bank, FSB, Hibernia National Bank,
Compass Bank and Bank of Scotland
10.2 First Amendment to First Amended and Restated Credit Agreement dated
November 4, 2002 among Ultra Resources, Inc., Bank One N.A., Union
Bank of California, N.A., Guaranty Bank, FSB, Hibernia National Bank
and Compass Bank (incorporated by reference to Exhibit 10.1 to the
Company's annual report on Form 10-K for the period ended December
31, 2002)
10.3 First Amended and Restated Credit Agreement dated March 1, 2002 among
Ultra Resources, Inc., Bank One N.A., Union Bank of California, N.A.,
Guaranty Bank, FSB, Hibernia National Bank and Compass Bank
(incorporated by reference to Exhibit 10.1 to the Company's annual
report on Form 10-K for the period ended December 31, 2001)
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
32.2 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act