UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE TRANSITION PERIOD FROM ______________ TO ________________

Commission file number 0-29370

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

Yukon Territory, Canada		N/A
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)

363 North Sam Houston Parkway E., Suite 1200, Houston, Texas (Address of principal executive offices)		77060 (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 þ NO o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)
YES þ NO o

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of July 29, 2005 was 153,409,036.

 

 

PART 1 — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

(Expressed in U.S. Dollars)

ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		For the Three Months Ended								For the Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
Revenues:
Natural gas sales		$	82,076,643			$	43,174,208			$	156,027,616			$	89,251,431
Oil sales			27,421,604				2,936,082				42,311,971				5,477,632
Total operating revenues			109,498,247				46,110,290				198,339,587				94,729,063
Expenses:
Production expenses and taxes			18,489,289				9,424,401				34,581,201				19,149,299
Depletion and depreciation			12,656,404				5,415,985				23,895,913				10,896,704
General and administrative			3,120,170				1,190,350				5,681,952				2,744,388
General and administrative — stock compensation			396,083				523,500				1,010,659				623,523
Total operating expenses			34,661,946				16,554,236				65,169,725				33,413,914
Operating income			74,836,301				29,556,054				133,169,862				61,315,149
Other income (expense):
Interest expense			(1,167,763	)			(848,742	)			(2,068,406	)			(1,948,912	)
Interest income			118,693				9,910				193,558				22,644
Total other income (expense)			(1,049,070	)			(838,832	)			(1,874,848	)			(1,926,268	)
Income, before income tax provision			73,787,231				28,717,222				131,295,014				59,388,881
Income tax provision			25,899,316				10,194,718				46,084,550				21,083,159
Net income			47,887,915				18,522,504				85,210,464				38,305,722
Retained earnings, beginning of period			202,610,860				75,921,734				165,288,311				56,138,516
Retained earnings, end of period		$	250,498,775			$	94,444,238			$	250,498,775			$	94,444,238
Income per common share — basic		$	0.31			$	0.12			$	0.56			$	0.26
Income per common share — fully diluted		$	0.30			$	0.12			$	0.53			$	0.24
Weighted average common shares outstanding — basic			152,929,693				149,929,660				151,903,632				149,722,174
Weighted average common shares outstanding — fully diluted			161,275,842				159,890,858				161,067,073				159,715,394

ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(Expressed in U.S. Dollars)		Six Months Ended
		June 30,
		2005				2004
Cash provided by (used in):
Operating activities:
Net income		$	85,210,464			$	38,305,722
Add (deduct) items not involving cash:
Depletion and depreciation			23,895,913				10,896,704
Deferred income taxes			46,084,550				21,083,159
Stock compensation			1,010,659				623,523
Net changes in non-cash working capital:
Restricted cash			(878	)			(629	)
Accounts receivable			(14,652,671	)			1,588,509
Inventory			(155,576	)			—
Prepaid expenses and other current assets			(17,917	)			(3,641,480	)
Accounts payable and accrued liabilities			26,105,193				(9,279,205	)
Other long-term obligations			388,552				2,699,709
Taxation-payable			(130,000	)			—
Cash provided by operating activities			167,738,289				62,276,012
Investing activities:
Oil and gas property expenditures			(111,001,119	)			(63,673,697	)
Oil and gas property expenditures in accounts payable			(14,171,171	)			(10,458,509	)
Inventory			(15,185,448	)			4,073,175
Purchase of capital assets			(762,569	)			(634,196	)
Cash used in investing activities			(141,120,307	)			(70,693,227	)
Financing activities:
Borrowings on long-term debt, gross			13,000,000				24,000,000
Payments on long-term debt, gross			(28,000,000	)			(9,000,000	)
Proceeds from exercise of options			8,423,075				744,413
Cash provided by (used in) financing activities			(6,576,925	)			15,744,413
Increase in cash during the period			20,041,057				7,327,198
Cash and cash equivalents, beginning of period			16,932,661				1,834,112
Cash and cash equivalents, end of period		$	36,973,718			$	9,161,310
Supplemental disclosures of cash flow information
Non-cash tax benefit of stock options exercised		$	24,547,479			$	3,223,453

ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(Expressed in U.S. Dollars)
		June 30,				December 31,
		2005				2004
Assets
Current assets
Cash and cash equivalents		$	36,973,718			$	16,932,661
Restricted cash			212,839				211,961
Accounts receivable			50,401,958				35,749,287
Deferred tax asset			1,316,379				1,327,489
Inventory			20,491,978				5,180,024
Prepaid expenses and other current assets			1,743,760				1,725,843
Total current assets			111,140,632				61,127,265
Oil and gas properties, using the full cost method of accounting
Proved			472,342,128				385,794,926
Unproved			90,157,488				88,839,460
Capital assets			1,824,906				1,424,367
Total assets		$	675,465,154			$	537,186,018
Liabilities and shareholders’ equity
Current liabilities
Accounts payable and accrued liabilities		$	40,067,492			$	14,238,836
Fair value of derivative instrument liability			3,750,366				3,739,406
Capital costs accrual			38,927,214				53,118,385
Total current liabilities			82,745,072				71,096,627
Bank indebtedness			87,000,000				102,000,000
Deferred income taxes			107,882,558				86,362,741
Other long-term obligations			10,492,380				9,734,904
Shareholders’ equity
Share capital			140,474,006				106,513,852
Treasury stock			(1,193,650	)			(1,193,650	)
Other comprehensive loss — fair value of derivative instruments			(2,433,987	)			(2,616,767	)
Retained earnings			250,498,775				165,288,311
Total shareholders’ equity			387,345,144				267,991,746
Total liabilities and shareholders’ equity		$	675,465,154			$	537,186,018

ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

(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 is incorporated 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, 2004, are unaudited and were prepared from the Company’s records. Balance sheet data as of December 31, 2004 was derived from the Company’s audited financial statements, but does not include all disclosures required by U.S. generally accepted accounting principles. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these 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 U.S. 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:

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 exploration and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and gas properties are amortized using the unit-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 on relative energy content. Operating fees received related to the properties in which the Company owns an interest are netted against expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost pool. Effective with the adoption of SFAS 143, asset retirement obligations are included in the base costs for calculating depletion.

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, generally using prices in effect at the end of the period held flat for the life of production excluding the estimated abandonment cost for properties with asset retirement obligations recorded on the balance sheet and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development. The effect of implementing SFAS 143 has no effect on the ceiling test calculation as the future cash outflows associated with settling asset retirement obligations are excluded from this calculation.

(g) Inventories:

Crude oil products and material and supplies inventories are carried at the lower of current market value or cost. Inventory costs include expenditures and others charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less. Crude oil product inventory at June 30, 2005 includes depletion and lease operating expenses of $754,817, associated with the Company’s crude oil production in China. Materials and supplies inventory of $19.7 million primarily includes the cost of pipe that will be utilized during the remainder of the Company’s 2005 drilling program and the beginning of the 2006 drilling program.

(h) Derivative transactions:

The Company has entered into commodity price risk management transactions to manage its exposure to gas price volatility. These transactions are in the form of price swaps with financial institutions and other credit worthy counterparties. 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 to the extent the hedges are effective.

(i) Income taxes:

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

(j) Earnings per share:

Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of stock options. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of the components of basic and diluted net income per common share:

		Three Months Ended								Six Months Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
Net income		$	47,887,915			$	18,522,504			$	85,210,464			$	38,305,722
Weighted average common shares outstanding during the period			152,929,693				149,929,660				151,903,632				149,722,174
Effect of dilutive instruments			8,346,149				9,961,198				9,163,441				9,993,220
Weighted average common shares outstanding during the period including the effects of dilutive Instruments			161,275,842				159,890,858				161,067,073				159,715,394
Basic earnings per share		$	0.31			$	0.12			$	0.56			$	0.26
Diluted earnings per share		$	0.30			$	0.12			$	0.53			$	0.24

On May 9, 2005 the outstanding shares of the Company were doubled as the result of a two for one stock split. The prior year numbers have been adjusted to reflect this change for comparative purposes.

(k) Use of estimates:

Preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States 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.

(l) Reclassifications:

Certain amounts in the financial statements of the prior periods have been reclassified to conform to the current period financial statement presentation.

(m) Accounting for stock-based compensation:

Statement of Financial Accounting Standards No. 123, “Accounting for Stock–Based Compensation” (SFAS No. 123), defines a fair value method of accounting for employee stock options and similar equity instruments. SFAS No. 123 allows for the continued measurement of compensation cost for such plans using the intrinsic value based method prescribed by APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), provided that pro forma results of operations are disclosed for those options granted. The Company accounts for stock options granted to employees and directors of the Company under the intrinsic value method. Had the Company reported compensation costs as determined by the fair value method of accounting for option grants to employees and directors, net income and net income per common share would approximate the following pro forma amounts:

		Three Months Ended								Six Months Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
Net income:
As reported		$	47,887,915			$	18,522,504			$	85,210,464			$	38,305,722
Deduct: Fair value of stock options issued net of tax,			(1,649,332	)			(575,202	)			(3,492,631	)			(1,132,978	)
Pro forma		$	46,238,583			$	17,947,302			$	81,717,833			$	37,172,744
Basic earnings per share:
As reported		$	0.31			$	0.12			$	0.56			$	0.26
Pro forma		$	0.30			$	0.12			$	0.54			$	0.25
Diluted earnings per share:
As reported		$	0.30			$	0.12			$	0.53			$	0.24
Pro forma		$	0.29			$	0.11			$	0.51			$	0.23

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 the following assumptions: at June 30, 2005, expected volatility of 30.8% and a risk free rate of 3.830% - 4.320%at June 30, 2004, expected volatility of 25.0% and a risk free rate of 4.35%. At June 30, 2005 options have expected lives of 6.5 years, and at June 30, 2004 options had expected lives of ten years.

(n) Revenue Recognition. Natural gas revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company records its entitled share of revenues based on estimated production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by third party pipeline statements or cash receipts. Since there is a ready market for natural gas, the Company sells the majority of its products soon after production at various locations at which time title and risk of loss pass to the buyer. Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.

Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title is transferred.

(o) Other comprehensive earnings (loss) is a term used to define revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of shareholders’ equity instead of net earnings (loss). The loss depicted on the balance sheet as other comprehensive loss is associated with unrealized losses related to the change in fair value of derivative instruments designated as cash flow hedges.

		Six Months Ended
		June 30, 2005				June 30, 2004
Net income		$	85,210,464			$	38,305,722
Unrealized loss on derivative instruments, net of tax			(2,433,987	)			(6,800,695	)
Total comprehensive income		$	82,776,477			$	31,505,027

(p) Impact of recently issued accounting pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (FAS 123R), “Share-based Payment.” FAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the vesting period. The amount of the compensation cost will be measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of January 1, 2006, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. Beginning after January 1, 2006 the Company will begin expensing share based compensation. All outstanding awards issued prior to this date will have fully vested.

2. ASSET RETIREMENT OBLIGATIONS:

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company has recorded a liability of $1,113,436 ($690,429 U.S. and $423,007 China) to account for future obligations associated with its assets in both the United States and China.

3. OIL AND GAS PROPERTIES:

		June 30,				December 31,
		2005				2004
Developed Properties:
Acquisition, equipment, exploration, drilling and environmental costs — Domestic		$	529,444,138			$	429,597,822
Acquisition, equipment, exploration, drilling and environmental costs — China			34,685,173				24,552,316
Less accumulated depletion, depreciation and amortization — Domestic			(84,570,680	)			(65,099,325	)
Less accumulated depletion, depreciation and amortization — China			(7,216,503	)			(3,255,887	)
			472,342,128				385,794,926
Unproven Properties:
Acquisition and exploration costs — Domestic			17,378,645				16,910,010
Acquisition and exploration costs — China			72,778,843				71,929,450
Net oil and gas properties		$	562,499,616			$	474,634,386

4. LONG-TERM LIABILITIES:

		June 30,				December 31,
		2005				2004
Bank indebtedness		$	87,000,000			$	102,000,000
Other long-term obligations			10,492,380				9,734,904
Total long-term debt		$	97,492,380			$	111,734,904

Bank indebtedness: The Company (through its subsidiary) participates in a revolving credit facility with a group of banks led by JP Morgan Chase Bank. On May 5, 2005 the Company signed a third amendment to second amended and restated credit agreement. The agreement specifies an aggregate borrowing base of $500 million and a commitment amount of $200 million. The commitment amount may be increased up to $500 million at any time at the request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. At June 30, 2005, the Company had $87 million outstanding and $113 million unused and available under the current committed amount.

The credit facility matures on May 1, 2010. The note bears interest at either the bank’s prime rate with no margin added up to the prime rate plus a margin of three-quarters of one percent (0.75%) based on the percentage of available credit drawn or at LIBOR plus a margin of one percent (1.00%) to one and three-quarters of one percent (1.75%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.25% to 0.375%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount.

The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the banks and may be decreased or increased depending on a number of factors, including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. If the borrowing base is reduced to an amount less than the balance outstanding, the Company has sixty days from the date of written notice of the reduction in the borrowing base to pay the difference. Additionally, the Company is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation, the Company’s U.S. subsidiary in which the China asset is held. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility. The notes are collateralized by a majority of the Company’s proved domestic oil and gas properties. At June 30, 2005, the Company had $87.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 4.4%. The Company was in compliance with all loan covenants at June 30, 2005.

Other long-term obligations: These costs relate to the long-term portion of production taxes payable, a liability associated with imbalanced production, the long-term portion of the fair value estimate of our hedging liability and our asset retirement obligations discussed in Note 2.

5. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES:

In September 2003, the AcSB (Accounting Standards Board) released revised transitional provisions for Stock-Based Compensation and Other Stock-Based Payments, Section 3870, to provide the same alternative methods of transition as is provided in the US for voluntary adoption of the fair value based method of accounting. These provisions permit either retroactive (with or without restatement) or prospective application of the recognition provisions to awards not previously accounted for at fair value. Prospective application is only available to enterprises that elect to apply the fair value based method of accounting to that type of award for fiscal years beginning before January 1, 2004.

The AcSB has also amended Section 3870 to require that all transactions whereby goods and services are received in exchange for stock-based compensation and other payments result in expenses that should be recognized in financial statements, and that this requirement would be applicable for financial periods beginning on or after January 1, 2004. Section 3870 requires that share-based transactions be measured on a fair value basis.

As described in Note 1, had the Company expensed the fair value of options vested during the period, net income would have been reported as $46,238,583 for the quarter ended June 30, 2005 and $81,717,833 for the six months ended June 30, 2005.

Recorded in other comprehensive loss in the equity section of the Company’s balance sheet is an offset of $2,433,987 to a liability that measures the 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 SFAS 133 which addresses accounting impacts of derivative instruments.

The AcSB issued a new Accounting Guideline (“Guideline”), AcG-13, Hedging Relationships, in December 2001 in connection with amendments to CICA Handbook Section 1650, Foreign Currency Translation. The Guideline is applicable to hedging relationships in effect in fiscal years beginning on or after July 1, 2003 (the AcSB changed the original effective date of January 1, 2002 in its December 2001 meeting, and further deferred the effective date in its September 2002 meeting). The Guideline is not applicable to prior periods, but requires the discontinuance of hedge accounting for hedging relationships established in prior periods that do not meet the conditions for hedge accounting at the date it is first applied.

The Guideline supplements some of the requirements on accounting for hedges of foreign currency items in Section 1650, but is equally applicable to accounting for hedges of other types of risk exposure. The Guideline deals with the identification, documentation, designation and effectiveness of hedges and also the discontinuance of hedge accounting, but does not specify hedge accounting methods.

The Guideline is intended to improve the quality and consistency of hedge accounting under Canadian GAAP. The Guideline incorporates certain features of the U.S. hedge accounting standards as requirements. The AcSB has attempted to avoid creating any additional GAAP differences, i.e., requirements that prevent an entity from adopting a U.S. requirement. However, Canadian hedge accounting remains inconsistent with U.S. GAAP in some fundamental ways.

6. SEGMENT INFORMATION

The Company has two reportable operating segments, one domestic and one foreign, which are in the business of natural gas and crude oil exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before price-risk management and other, general and administrative expenses and interest expense. The Company’s reportable operating segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:

		Three Months Ended June 30,
		2005												2004
		Domestic				China				Total				Domestic				China				Total
Oil and gas sales		$	87,899,347			$	21,598,900			$	109,498,247			$	46,110,290				—			$	46,110,290
Costs and Expenses:
Depletion and depreciation			10,236,718				2,419,686				12,656,404				5,415,985				—				5,415,985
Lease operating expenses			2,032,364				2,166,000				4,198,364				1,246,745				—				1,246,745
Production taxes			10,204,694				—				10,204,694				5,430,719				—				5,430,719
Gathering			4,086,231				—				4,086,231				2,746,937				—				2,746,937
Operating income			61,339,340				17,013,214				78,352,554				31,269,904				—				31,269,904
General and administrative											3,516,253												1,713,850
Other expense											1,049,070												838,832
Income before income taxes										$	73,787,231											$	28,717,222
Capital expenditures		$	53,416,720			$	3,768,152			$	57,184,872			$	27,358,587			$	1,326,262			$	28,684,849
Net oil and gas properties		$	462,252,103			$	100,247,513			$	562,499,616			$	273,757,358			$	87,493,335			$	361,250,693

		Six Months Ended June 30,
		2005												2004
		Domestic				China				Total				Domestic				China				Total
Oil and gas sales		$	166,809,736			$	31,529,851			$	198,339,587			$	94,729,063				—			$	94,729,063
Costs and Expenses:
Depletion and depreciation			19,906,227				3,989,686				23,895,913				10,896,704				—				10,896,704
Lease operating expenses			4,017,670				3,620,000				7,637,670				2,529,669				—				2,529,669
Production taxes			19,226,756				—				19,226,756				11,100,496				—				11,100,496
Gathering			7,716,775				—				7,716,775				5,519,134				—				5,519,134
Operating income			115,942,308				23,920,165				139,862,473				64,683,060				—				64,683,060
General and administrative											6,692,611												3,367,911
Other expense											1,874,848												1,926,268
Income before income taxes										$	131,295,014											$	59,388,881
Capital expenditures		$	100,018,868			$	10,982,251			$	111,001,119			$	57,150,607			$	6,523,090			$	63,673,697
Net oil and gas properties		$	462,252,103			$	100,247,513			$	562,499,616			$	273,757,358			$	87,493,335			$	361,250,693

ITEM 2 — MANAGEMENTS’ DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company. Except as otherwise indicated all amounts are expressed in U.S. dollars. We operate in one segment, natural gas and oil exploration and development with two geographical segments; the United States and China.

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. GAAP. In addition, application of generally accepted accounting principles requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates, judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated.

The Company currently generates the majority of its revenue, earnings and cash from the production and sales of natural gas and oil from its property in southwestern Wyoming. The price of natural gas in the southwest Wyoming region is a critical factor to the Company’s business. The price of gas in southwest Wyoming historically has been volatile. The average annual realizations for the period 2003-2005 have ranged from $3.84 to $5.85 per Mcf. This volatility could be very detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into derivative and forward sales contracts for gas in southwest Wyoming. The average realization for the Company’s gas during the first six months of 2005 was $5.72 per Mcf, basis Opal, Wyoming, including the effect of hedges. The Company continued producing from the first of the nine fields discovered on its oil properties offshore Bohai Bay, China. The Company’s average realized crude oil price on its Boahi Bay production was $39.50 USD per barrel for the six months ended June 30, 2005.

The Company has grown its natural gas and oil production significantly over the past three years and management believes it has the ability to continue growing production by drilling already identified locations on its leases in Wyoming and by bringing into production the already discovered oilfields in China. The Company delivered 72% production growth on an Mcfe basis during the six months ended June 30, 2005 as compared to the same six months in 2004.

The Company uses the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration for and development of oil and gas reserves are capitalized to the Company’s cost centers. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. The Company conducts operations in both the United States and China. Separate cost centers are maintained for each country in which the Company has operations. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.

RESULTS OF OPERATIONS

QUARTER ENDED JUNE 30, 2005 VS. QUARTER ENDED JUNE 30, 2004

During the quarter, production increased 84% on an equivalent basis to 17.7 Bcfe from 9.6 Bcfe for the same quarter in 2004 attributable to the Company’s successful drilling activities along with continued production in China which commenced in July of 2004. This increased production coupled with average realized prices for natural gas increasing 24% to $5.85 per Mcf along with average realized prices for oil increasing 48% to $53.99 per barrel resulted in a 138% increase in revenues to $109.5 million.

In Wyoming, production costs increased to $16.3 million for the quarter ended June 30, 2005 compared to $9.4 million for the quarter ended June 30, 2004 due to increased production along with increased prices received for that production. On a unit of production basis, LOE costs increased slightly to $0.14 per Mcfe for the quarter June 30, 2005 compared to $0.13 per Mcfe for the same quarter in 2004. During the second quarter of 2005 production taxes were $10.2 million compared to $5.4 million for the same quarter in 2004, or $0.70 per Mcfe, compared to $0.57 per Mcfe. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased the costs on a per unit basis. Gathering fees were $4.1 million for the quarter ended June 30, 2005 compared to $2.8 million for the quarter ended June 30, 2004 which decreased slightly to $0.28 per Mcfe compared to $0.29 for the quarter ended June 30, 2004.

In Wyoming, depletion, depreciation and amortization (“DD&A”) expenses increased to $10.2 million during the quarter ended June 30, 2005 from $5.4 million for the same period in 2004, attributable to increased production volumes and a higher depletion rate, which is primarily associated with forecasted increased future development costs. On a unit basis, DD&A increased to $0.70 per Mcfe for the quarter ended June 30, 2005 from $0.56 for the quarter ended June 30, 2004.

In China, production costs were $2.2 million for the quarter ended June 30, 2005 ($0.72 per Mcfe or $4.32 per BOE). DD&A was $2.4 million ($0.80 per Mcfe or $4.80 per BOE).

For the quarter ended June 30, 2005, net income before income taxes increased 157% to $73.8 million and income tax provision increased 154% to $25.9 million. Net income increased 159% to $47.9 million or $0.30 per diluted share.

General and administrative expenses increased 162% to $3.1 million during the quarter ended June 30, 2005 compared to $1.2 million for the same period in 2004. This increase was primarily attributable to increased audit fees associated with the implementation of an internal audit function implemented by the Company to support its compliance with the Sarbanes-Oxley Act coupled with increased external audit fees.

Income tax provision for the period increased to $25.9 million during the second quarter of 2005 compared to $10.2 million during the second quarter of 2004. This increase was attributable to an increase in net income from continuing operations. The Company’s effective tax rate was 35.1% at June 30, 2005 compared to 35.5% at June 30, 2004.

SIX-MONTHS ENDED JUNE 30, 2005 VS. SIX-MONTHS ENDED JUNE 30, 2004

During the six-months ended June 30, 2005, production increased 72% on an equivalent basis to 33.3 Bcfe from 19.3 Bcfe for the same six-months in 2004. The increase is primarily attributable to the additional wells drilled and completed during 2004 along with the increased drilling and completion during the first six-months of the year. Increased production coupled with average realized prices for natural gas increasing 18% on an equivalent basis to $5.72 per Mcf during the six-month period ended June 30, 2005 from $4.84 per Mcf for the same period in 2004 resulted in a 109% increase in revenues to $198.3 million. For the six months ended June 30, 2005 oil prices increased 41% to $51.98 per barrel compared to $36.77 per barrel for the same six months of 2004.

In Wyoming, production costs increased 62% to $30.9 million primarily due to the 48% increase in production and higher production taxes driven by the 76% increase in revenues. Production taxes are calculated as a percentage of revenue. Therefore, higher prices received increased the costs on a per unit basis. On a unit of production basis, production costs increased to $1.09 per Mcfe during the first six months of 2005 compared to $0.99 per Mcfe for the first six months of 2004. The increase in production costs was attributable almost wholly to the increase in production taxes arising from higher revenues.

In China, the Company produced 798,253 barrels of crude oil for the six months ended June 30, 2005 with an average realized price of $39.50 per barrel resulting in revenues of $31.5 million. Production costs for the first six months of 2005 were $3.6 million ($0.76 per Mcfe or $4.56 per BOE). DD&A was $4.0 million ($0.83 per Mcfe or $4.98 per BOE).

For the six months ended June 30, 2005 net income before income taxes increased 121% to $131.3 million and income tax provision increased by 119% to $46.1 million. Net income increased 123% to $85.2 million, or $0.53 per diluted share.

General and administrative expenses increased 107% to $5.7 million for the six months ended June 30, 2005 compared to $2.7 million for the same period in 2004. This increase was primarily attributable to increased audit fees associated with the implementation of an internal audit function implemented by the Company to support its compliance with the Sarbanes-Oxley Act coupled with increased external audit fees.

The Company’s income tax provision increased to $46.1 million during the first six months of 2005 compared to $21.1 million for the same period in 2004. This increase was attributable to an increase in net income from continuing operations. The Company’s effective tax rate was 35.1% at June 30, 2005 compared to 35.5% at June 30, 2004.

LIQUIDITY AND CAPITAL RESOURCES

During the six month period ended June 30, 2005, the Company relied on cash provided by operations to finance its capital expenditures. The Company participated in the drilling and completion of 46 wells in Wyoming and continued to participate in the exploration and development processes in the China blocks including the ongoing batch drilling program for the development wells. For the six-month period ended June 30, 2005, net capital expenditures were $111 million. At June 30, 2005, the Company reported a cash position of $37.0 million compared to $9.2 million at June 30, 2004. Working capital at June 30, 2005 was $28.4 million as compared to $2.1 million at June 30, 2004. As of June 30, 2005, the Company had incurred bank indebtedness of $87.0 million compared to $114 million during the same six months in 2004. The company incurred other long-term obligations of $10.5 million comprised of items payable in more than one year, primarily related to production taxes.

The Company’s positive cash provided by operating activities, along with the availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2005, which are currently projected to be $290 million. Of the $290 million budget, the Company plans to spend approximately $270 million of its 2005 budget in Wyoming and approximately $20 million in China. Of the $270 million for Wyoming, the Company plans to drill or participate in an estimated 105 gross wells in 2005, of which approximately 18% will be for exploration wells and the remaining will be for development wells. Of the $20 million budgeted for China, approximately $15 million will be for development activity and the balance will be for exploratory/appraisal activity. The Company currently has no budget for acquisitions in 2005.

The Company (through its subsidiary) participates in a revolving credit facility with a group of banks led by JP Morgan Chase Bank. On May 5, 2005 the Company signed a third amendment to second amended and restated credit agreement. The agreement specifies an aggregate borrowing base of $500 million and a commitment amount of $200 million. The commitment amount may be increased up to $500 million at any time at the request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. The credit facility matures on May 1, 2010. The note bears interest at either the bank’s prime rate with no margin added up to prime rate plus a margin of three-quarters of one percent (0.75%) based on the percentage of available credit drawn or at LIBOR plus a margin of one percent (1.00%) to one and three-quarters of one percent (1.75%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.25% to 0.375%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount. The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the banks and may be 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 compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation, the Company’s U.S. subsidiary in which the China asset is held. 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 a reduction in the borrowing base, be required to repay the credit facility. The notes are collateralized by a majority of the Company’s proved domestic oil and gas properties. At June 30, 2005, the Company had $87.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 4.4%. The Company was in compliance with all loan covenants at June 30, 2005.

During the six-months ended June 30, 2005, net cash provided by operating activities was $167.7 million as compared to $62.3 million for the six-months ended June 30, 2004. The increase in cash provided by operating activities was attributable to the increase in earnings.

During the six-months ended June 30, 2005, cash used in investing activities was $141.1 million as compared to $70.7 million for the six-months ended June 30, 2004. The change is primarily attributable to increased activity for drilling and completion activity in Wyoming and China.

During the six-months ended June 30, 2005, cash provided by (used in) financing activities was $(6.6) million as compared to $15.7 million for the six-months ended June 30, 2004. The change is primarily attributable to decreased borrowings under the senior credit facility.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of June 30, 2005.

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, 2004 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, which contributes the majority of the Company’s oil and gas revenue. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations averaged $5.72 per Mcf during the six months ended June 30, 2005. This average price includes the effects of hedging and gas balancing between working interest owners.

The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes fixed price physical contracts as well as price swaps, which are placed with major financial institutions or with counter-parties of high credit quality that it believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices the Company receives. Under SFAS 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. The Company currently does not have any derivative contracts in place that do not qualify as a cash flow hedge.

During the first six months of 2005, the total impact of the Company’s price swaps was a reduction in gas revenues of $2.4 million. The effect of fixed price physical contracts is not included in this amount. The Company does not currently hedge its oil production.

At June 30, 2005, the Company had the following open derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price (all prices southwest Wyoming basis).

Average

Unrealized

Remaining Contract

Volume-

Price /

loss at

Type

Period

MMBTU / day

MMBTU

6/30/05*

Swap

Jul 2005 — Dec 2005

10,000

$

4.42

$

3,750,367

12

ITEM 4 — CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures. The Company’s management, including the Company’s principal executive and 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 and financial officer has concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission as of the end of the period covered by this Quarterly Report on Form 10-Q.

(b) Changes in Internal Controls. There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART 2 — OTHER INFORMATION

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.

None

None

The Company held its annual meeting on April 29, 2005. 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 — 52,208,800 voted in favor, 535,381 voted against and 1,039,656 votes abstained.
W. Charles Helton — 52,669,344 voted in favor, 79,302 voted against and 1,035,191 votes abstained.
James E. Nielson — 52,660,816 voted in favor, 73,690 voted against and 1,049,331 votes abstained.
James C. Roe — 52,674,628 voted in favor, 73,628 voted against and 1,035,581 votes abstained.
Robert E. Rigney — 52,662,071 voted in favor, 89,425 voted against and 1,032,341 votes abstained.

The shareholders of the Company also approved the re-appointment of KPMG, LLP as the Company’s independent auditors for 2005. There were 56,319,762 votes in favor of approval of the re-appointment of KPMG, LLP as the Company’s auditors, 0 votes against and 1,078,422 votes abstained.

The shareholders of the Company approved a two for one forward stock split with 56,320,334 votes in favor of the stock split and 107,834 votes abstaining.

The shareholders approved the Company’s 2005 Stock Incentive Plan with 17,323,157 shares voting to approve the Plan and 13,092,960 shares voting against the Plan. The Plan was therefore approved by a majority of the votes cast.

A total of 57,494,735 shares were voted by 293 shareholders, representing 76% of the Company’s outstanding shares.

None

(a) Exhibits

3.1 Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

3.2 By-Laws of Ultra Petroleum Corp — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

4.1 Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

10.1 Third to Amendment to Second Amended and Restated Credit Agreement dated May 5, 2005 among Ultra Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of California N.A., Hibernia National Bank, Guaranty Bank FSB, Compass Bank, Bank of Scotland and Bank of America, N.A.

31.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(a)

32.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(b)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

				ULTRA PETROLEUM CORP.
Date July 29, 2005		By:
				Name: Michael D. Watford
				Title: Chief Executive Officer
				(on behalf of the registrant and as the Principal Financial Officer)

Index to Exhibits

3.1 Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

3.2 By-Laws of Ultra Petroleum Corp — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

4.1 Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

10.1 Third to Amendment to Second Amended and Restated Credit Agreement dated May 5, 2005 among Ultra Resources, Inc., JPMorgan Chase Bank N.A., Union Bank of California N.A., Hibernia National Bank, Guaranty Bank FSB, Compass Bank, Bank of Scotland and Bank of America, N.A.

31.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(a)

32.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(b)