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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 SEPTEMBER 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 November 4, 2003 was 74,371,668.
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 Nine Months Ended
September 30, September 30,
------------------------------- ----------------------------
2003 2002 2003 2002
------------ ------------- ------------ ------------
Revenues:
Natural gas sales $ 27,711,651 $ 7,578,471 $ 72,835,464 $ 23,440,699
Oil sales 1,578,976 1,092,561 4,591,912 2,480,039
------------ ------------- ------------ ------------
29,290,627 8,671,032 77,427,376 25,920,738
Expenses:
Production expenses and taxes 6,179,424 2,556,096 16,354,828 7,137,225
Depletion and depreciation 4,033,606 2,340,270 11,091,346 6,193,858
General and administrative 1,468,553 1,095,113 4,210,029 3,154,376
General and administrative -
stock compensation - 415,000 1,018,220 1,211,165
------------ ------------- ------------ ------------
11,681,583 6,406,479 32,674,423 17,696,624
Operating income 17,609,044 2,264,553 44,752,953 8,224,114
Other income:
Interest expense (747,125) (706,705) (2,151,559) (1,912,922)
Interest income
6,668 5,221 26,431 17,555
------------ ------------- ------------ ------------
(740,457) (701,484) (2,125,128) (1,895,367)
Income for the period, before income tax
provision 16,868,587 1,563,069 42,627,825 6,328,747
Income tax provision - deferred 6,540,600 601,783 16,458,292 2,349,157
Net income for the period 10,327,987 961,286 26,169,533 3,979,590
Retained earnings, beginning of period 26,657,423 5,752,660 10,815,877 2,734,356
------------ ------------- ------------ ------------
Retained earnings, end of period $ 36,985,410 $ 6,713,946 $ 36,985,410 $ 6,713,946
============ ============= ============ ============
Income per common share - basic $ 0.14 $ 0.01 $ 0.35 $ 0.05
============ ============= ============ ============
Income per common share - fully diluted $ 0.13 $ 0.01 $ 0.33 $ 0.05
============ ============= ============ ============
Weighted average common shares
outstanding - basic 74,279,516 73,716,932 74,170,485 73,716,932
============ ============= ============ ============
Weighted average common shares
outstanding - fully diluted 78,537,895 77,561,888 78,335,831 77,536,290
============ ============= ============ ============
2
ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Expressed in U.S. Dollars) Nine Months Ended
September 30,
---------------------------
2003 2002
------------ ------------
Cash provided by (used in):
Operating activities:
Net income for the period $ 26,169,533 $ 3,979,590
Add (deduct)
Items not involving cash:
Depletion and depreciation 11,091,346 6,193,858
Deferred income taxes 16,458,291 2,349,158
Stock compensation 1,018,220 1,211,165
Net changes in non-cash working capital:
Restricted cash (1,044) (1,720)
Accounts receivable (3,313,559) 922,893
Prepaid expenses and other current assets (3,373,345) (2,494,282)
Accounts payable and accrued liabilities 3,341,399 (6,263,595)
Other long-term obligations 970,569 3,294,599
------------ ------------
52,361,410 9,191,666
Investing activities:
Oil and gas property expenditures (68,499,293) (39,870,660)
Oil and gas property expenditures in accounts payable 24,288,871 -
Purchase of capital assets (553,212) (640,439)
------------ ------------
(44,763,634) (40,511,099)
Financing activities:
Long-term debt (7,000,000) 31,000,000
Repurchased shares - (1,193,650)
Proceeds from exercise of options 569,657 899,931
------------ ------------
(6,430,343) 30,706,281
Increase in cash during the period 1,167,433 (613,152)
Cash and cash equivalents, beginning of period 1,417,711 1,379,462
------------ ------------
Cash and cash equivalents, end of period $ 2,585,144 $ 766,310
============ ============
3
ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Expressed in U.S. Dollars)
September 30, December 31,
2003 2002
------------ ------------
Assets
Current assets
Cash and cash equivalents $ 2,585,144 $ 1,417,711
Restricted cash 210,350 209,306
Accounts receivable 14,712,042 11,398,483
Prepaid expenses and other current assets 3,847,624 474,279
------------ ------------
21,355,160 13,499,779
Oil and gas properties, using the full cost method of
accounting 265,452,490 207,362,408
Capital assets 1,175,565 1,011,699
------------ ------------
Total assets $287,983,215 $221,873,886
============ ============
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities $ 47,614,070 $ 17,914,860
Long-term debt 79,000,000 86,000,000
Deferred income taxes 25,443,181 10,033,174
Other long-term obligations 4,829,379 3,858,810
Shareholders' equity
Share capital 96,979,356 95,098,690
Treasury stock (1,193,650) (1,193,650)
Other comprehensive loss - fair value of derivative
instruments (1,674,531) (653,875)
Retained earnings 36,985,410 10,815,877
------------ ------------
131,096,585 104,067,042
Total liabilities and shareholders' equity $287,983,215 $221,873,886
============ ============
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 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
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) 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 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 Nine Months Ended
---------------------------- -----------------------------
September 30, September 30, September 30, September 30,
2003 2002 2003 2002
------------ ------------ ------------ -----------
Net income $ 10,327,987 $ 961,286 $ 26,169,533 $ 3,979,590
============ ============ ============ ===========
Weighted average common shares
outstanding during the period 74,279,516 73,716,932 74,170,485 73,716,932
Effect of dilutive instruments 4,258,379 3,844,956 4,165,346 3,819,358
------------ ------------ ------------ -----------
Weighted average common shares outstanding
during the period including the effects of
dilutive instruments 78,537,895 77,561,888 78,335,831 77,536,290
============ ============ ============ ===========
Basic earnings per share $ 0.14 $ 0.01 $ 0.35 $ 0.05
============ ============ ============ ===========
Diluted earnings per share $ 0.13 $ 0.01 $ 0.33 $ 0.05
============ ============ ============ ===========
(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 (loss) and net income (loss) per common share would
approximate the following pro forma amounts:
6
Three Months Ended Nine Months Ended
---------------------------------- -----------------------------------
September 30, September 30, September 30, September 30,
2003 2002 2003 2002
------------- ------------- -------------- -------------
Net income:
As reported $ 10,327,987 $ 961,286 $ 26,169,533 $ 3,979,590
Pro forma $ 9,587,818 $ 414,999 $ 25,429,364 $ 3,433,303
Basic earnings per share:
As reported $ 0.14 $ 0.01 $ 0.35 $ 0.05
Pro forma $ 0.13 $ 0.01 $ 0.34 $ 0.05
Diluted earnings per share:
As reported $ 0.13 $ 0.01 $ 0.33 $ 0.05
Pro forma $ 0.12 $ 0.01 $ 0.32 $ 0.04
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% at
September 30, 2003. All options have expected lives of ten years.
2. OIL AND GAS PROPERTIES:
September 30, December 31,
2003 2002
------------------------------------
Developed Properties:
Acquisition, equipment, exploration, drilling and
environmental costs $ 208,504,374 $ 150,986,843
Less accumulated depletion, depreciation and amortization (33,516,605) (22,816,605)
------------- -------------
174,987,769 128,170,238
Unproven Properties:
China 75,469,724 64,873,186
Acquisition and exploration costs 14,994,997 14,318,984
------------- -------------
$ 265,452,490 $ 207,362,408
============= =============
3. LONG-TERM DEBT:
September 30, December 31,
2003 2002
------------------------------------
Bank indebtedness $ 79,000,000 $ 86,000,000
Short-term obligations to be refinanced - 3,858,810
============= =============
$ 79,000,000 $ 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 million and an aggregate borrowing base of $155 million at
May 14, 2003. At September 30, 2003, the Company had $79 million outstanding and
$76 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 sixty days from date
of notice 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 September 30, 2003, the Company was in compliance with
the covenants and required ratios of the bank facility.
The Company has secured this debt by a majority of it's 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 FASB Statement No. 123, "Accounting for Stock-Based Compensation"; however,
there was an exposure draft issued in December 2002 that would essentially
harmonize Canadian accounting standards to US GAAP. The proposed effective date
for implementing the harmonization of accounting for 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 which
addresses accounting impacts of derivative instruments. Currently under Canadian
GAAP the future
7
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:
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, this Statement amends the disclosure requirements of
FASB 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 September 30, 2003, the pro-forma net income,
had the Company adopted the provisions of SFAS No. 123, equals $9,587,818.
ITEM 2 - MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
QUARTER ENDED SEPTEMBER 30, 2003 VS. QUARTER ENDED SEPTEMBER 30, 2002
OPERATING REVENUES
Oil and gas revenues increased to $29,290,627 for the quarter ended September
30, 2003 from $8,671,032 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 67% to
6.6 Bcf, up from 4.0 Bcf, while condensate increased to 50 thousand barrels from
36 thousand barrels for the same period in 2002. During the quarter ended
September 30, 2003 the average product prices for gas and condensate were $4.17
per Mcf and $31.37 per barrel, respectively, compared to $1.91 per Mcf and
$30.21 per barrel for the same period in 2002.
PRODUCTION EXPENSES AND TAXES
During the quarter ended September 30, 2003 production expenses and taxes
increased to $6,179,424 from $2,556,096 for the quarter ended September 30,
2002. Direct lease operating expenses increased to $872,364 for the quarter
ended September 30, 2003 from $605,335 for the same period in 2002. On a per
unit of production basis, these costs decreased to $.13 per Mcfe in September
2003, as compared to $.15 per Mcfe in September 2002. Production taxes for the
third quarter 2003 were $3,407,541, compared to $744,429 in third quarter 2002
or $.49 per Mcfe in third quarter 2003, compared to $.18 per Mcfe in third
quarter 2002. Production taxes are calculated based on a percentage of revenue
from production, excluding the effects of hedging and imbalances, therefore
higher realized prices and production contributed to the increase. Gathering
fees for the quarter ended September 30, 2003 increased to $1,899,519 from
$1,206,332 for the same period in 2002 based on higher production levels. On a
per Mcfe basis the rate decreased to $.27 for the third quarter ended September
30, 2003 from $.29 for the same quarter in 2002.
DEPLETION AND DEPRECIATION
Depletion, depreciation and amortization expenses ("DD&A") were $4,033,606
during the quarter ended September 30, 2003 compared to $2,340,270 for the same
period in 2002. On a per unit basis, DD&A increased to $.58 per Mcfe, from $.56
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 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 $1,468,553 during the quarter
ended September 30, 2003 from $1,095,113 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 $747,125 in third quarter 2003 from
$706,705 in third quarter 2002. This increase in interest expense was
attributable to the increase in borrowings under the senior credit facility,
which are partially offset by lower overall interest rates.
8
INCOME TAXES
The Company recorded deferred income tax expense of $6,540,600 for the quarter
ended September 30, 2003, compared to $601,783 for the quarter ended September
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 tax expense
evenly throughout the year at a statutory rate of 38.5%.
NINE MONTHS ENDED SEPTEMBER 30, 2003 VS. NINE MONTHS ENDED SEPTEMBER 30, 2002
OPERATING REVENUES
Oil and gas revenues increased to $77,427,376 for the nine months ended
September 30, 2003 from $25,920,738 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 nine months ended September 30, 2003, the Company's
production increased by 70% on an Mcf equivalent basis, to 18.3 Bcf of gas, and
148 thousand barrels of condensate, up from 10.7 Bcf of gas and 99 thousand
barrels of condensate for the same nine months in 2002. During the nine months
ended September 30, 2003 the average product prices for gas and condensate were
$3.99 per Mcf and $31.04 per barrel, respectively, compared to $2.18 per Mcf and
$24.93 per barrel for the same period in 2002.
PRODUCTION EXPENSES AND TAXES
During the nine months ended September 30, 2003 production expenses and taxes
increased to $16,354,828 from $7,137,225 for the nine months ended September 30,
2002. Direct lease operating expenses increased to $2,484,784 for the nine
months ended September 30, 2003 from $1,510,479 for the same period in 2002. On
a per unit of production basis, these costs remained a constant $.13 per Mcfe in
a nine-month to nine-month comparison. Production taxes for the nine months
ended September 30, 2003 were $8,674,351, compared to $2,463,468 during the same
period in 2002 or $.45 per Mcfe at September 2003, compared to $.22 per Mcfe at
September 2002. Production taxes are calculated based on a percentage of revenue
from production, excluding the effects of hedging and imbalances, therefore both
increased production and realized prices contributed to the increase. Gathering
fees for the nine months ended September 30, 2003 increased to $5,195,693 from
$3,163,278 for the same period in 2002, the increase in gathering fees is
primarily attributable to higher production volumes.
DEPLETION AND DEPRECIATION
Depletion, depreciation and amortization expenses (DD&A) increased to
$11,091,346 during the nine months ended September 30, 2003 compared to
$6,193,858 for the same period in 2002. On a per unit basis, DD&A increased to
$.58 per Mcfe, from $.55 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 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 $4,210,029 during the nine months
ended September 30, 2003 as compared to $3,154,376 for the same period in 2002.
The increase in general and administrative expenses 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 $2,151,559 during the nine months
ended September 30, 2003 compared to $1,912,922 for the same period in 2002.
This increase in interest expense was attributable to the increase in borrowings
under the senior credit facility.
INCOME TAXES
The Company recorded deferred income tax expense of $16,458,292 at an effective
rate of 38.5% for the nine months ended September 30, 2003, compared to
$2,349,157 at an effective rate of 37% for the nine months ended September 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 nine month period ended September 30, 2003, the Company relied on
cash provided by operations along with borrowings under it's credit facility to
finance its capital expenditures. The Company participated in the drilling of 51
wells in Wyoming and 10 wells in China, and continued to participate in the
development process in the China blocks. For the nine-month period ended
September 30, 2003 net capital expenditures were $69 million. At September 30,
2003, the Company reported a cash position of $2.6 million compared to $766
thousand at September 30, 2002. Working capital deficit at September 30, 2003
was $(26.3) million as compared to $(4.4) million at December 31, 2002. As of
September 30, 2003, the Company had incurred bank indebtedness of $79.0 million
and other long-term obligations of $4.8 million comprised of items payable in
more than one year.
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 2003, which are currently
projected to be $130.0 million. Of the $130.0 million budget, the Company plans
to spend approximately $110.0 million of its 2003 budget in Wyoming and
approximately $20.0 million in China. Of the $110.0 million for Wyoming, the
Company plans to drill or participate in an estimated 64-66 gross wells in 2003,
of which
9
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 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 September 30, 2003, the Company had $79.0 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 September 30, 2003.
During the nine-months ended September 30, 2003, net cash provided by operating
activities was $52.4 million as compared to $9.2 million for the nine-months
ended September 30, 2002. The increase in cash provided by operating activities
was attributable to the increase in earnings and an increase in items not
involving cash.
During the nine-months ended September 30, 2003, cash used in investing
activities was $44.8 million as compared to $40.5 million for the nine-months
ended September 30, 2002. The change is primarily attributable to increased
activity for drilling and completion activity in Wyoming.
During the nine-months ended September 30, 2003, cash provided by (used in)
financing activities was $(6.4) million as compared to $30.7 million for the
nine-months ended September 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 $3.99 per Mcf during the nine months ended September 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 nine months of 2003, the total impact
of the Company's hedges was a reduction in gas revenues of $3,436,975. The
Company does not currently hedge its oil production.
In the first nine months of 2003, the Company participated in swaps covering
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, Wyoming), 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, Wyoming).
During the third quarter of 2003, the Company entered into swaps covering 20,000
MMBtu, or approximately 18 MMcf of gas per day, for calendar year 2004 at a
weighted average price of $4.088/MMBtu, or approximately $4.33 per Mcf.
Additionally, the Company entered into forward fixed price physical sales
covering approximately 30,000 MMBtu gross (24,000 MMBtu, or approximately 22.6
MMcf net) of gas per day for calendar year 2004 at a weighted average net price
of $4.22 per MMBtu or $4.48 per Mcf. In aggregate these transactions have
10
hedged 16,060,000 MMBtu of net gas for calendar year 2004 at a weighted average
price of $4.16 per MMBtu, or approximately $4.41 per Mcf.
The tables below summarize the hedges in place at September 30, 2003:
Calendar Year - 2003
Type Period Daily Volume MMBTU Price / MMBtu at 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
Calendar Year - 2004
Type Period Daily Volume MMBTU Price / MMBtu at OPAL WY
- ---------------------------------------------------------------------------------------------
Fixed Price Sale Calendar 2004 5,000 $ 4.27
Fixed Price Sale 1st-3rd Qtr 2004 10,000 $4.315
Fixed Price Sale 4th Qtr 2004 10,000 $4.285
Fixed Price Sale Calendar 2004 5,000 $ 4.02
Fixed Price Sale Calendar 2004 5,000 $ 4.29
Fixed Price Sale Calendar 2004 5,000 $ 4.15
Swap Calendar 2004 10,000 $ 4.08
Swap Calendar 2004 5,000 $ 4.17
Swap Calendar 2004 5,000 $ 4.02
These hedges represent approximately 45% of the Company's forecasted production
for the period from April 1, 2003 to October 31, 2003, approximately 30% of the
Company's forecasted production for calendar year 2003 and approximately 42% of
forecasted production for calendar year 2004.
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 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
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
11
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
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
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 November 12, 2003 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
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
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