10-Q 1 h07878e10vq.txt ULTRA PETROLEUM CORP.- PERIOD ENDED: JUNE 30, 2003 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