Edgar Filing: ULTRA PETROLEUM CORP

e10vq

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, 2008


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		(I.R.S. employer
incorporation or organization)		identification number)

363 North Sam Houston Parkway, 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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO þ

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of July 31, 2008 was 152,833,061.

TABLE OF CONTENTS


	PART I — FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS	3
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	21
ITEM 4	CONTROLS AND PROCEDURES	22
	PART II — OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	23
ITEM 1A.	RISK FACTORS	23
ITEM 2.	CHANGES IN SECURITIES AND USE OF PROCEEDS	23
ITEM 3.	DEFAULTS IN SENIOR SECURITIES	23
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS	24
ITEM 5.	OTHER INFORMATION	24
ITEM 6.	EXHIBITS	25
SIGNATURES		26
EXHIBIT INDEX		27
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
				(Unaudited)
	(Amounts in thousands of U.S. dollars, except
	per share data)
Revenues:
Natural gas sales	$	263,327		$	116,421		$	512,449		$	263,705
Oil sales		30,794			14,451			52,809			23,743

Total operating revenues		294,121			130,872			565,258			287,448

Expenses:
Lease operating expenses		8,562			5,573			19,299			10,251
Production taxes		35,776			14,694			66,711			32,207
Gathering fees		8,766			6,980			18,764			13,473
Transportation charges		12,013			—			21,671			—
Depletion and depreciation		42,780			32,591			85,030			62,221
General and administrative		4,449			3,421			8,794			6,639

Total operating expenses		112,346			63,259			220,269			124,791

Operating income		181,775			67,613			344,989			162,657

Other income (expense), net:
Interest expense		(4,543	)		(4,221	)		(9,814	)		(6,921	)
Interest income		127			309			277			636

Total other income (expense), net		(4,416	)		(3,912	)		(9,537	)		(6,285	)

Income before income tax provision		177,359			63,701			335,452			156,372
Income tax provision		62,603			23,949			119,337			55,978

Net income from continuing operations		114,756			39,752			216,115			100,394
Income from discontinued operations, net of tax		482			9,317			415			15,266

Net income		115,238			49,069			216,530			115,660
Retained earnings, beginning of period		989,112			691,375			887,820			624,784

Retained earnings, end of period	$	1,104,350		$	740,444		$	1,104,350		$	740,444


Basic Earnings per Share:
Income per common share from continuing operations	$	0.75		$	0.26		$	1.41		$	0.66

Income per common share from discontinued operations	$	0.00		$	0.06		$	0.00		$	0.10

Net Income per common share	$	0.75		$	0.32		$	1.41		$	0.76


Fully Diluted Earnings per Share:
Income per common share from continuing operations	$	0.73		$	0.25		$	1.37		$	0.63

Income per common share from discontinued operations	$	0.00		$	0.06		$	0.00		$	0.10

Net Income per common share	$	0.73		$	0.31		$	1.37		$	0.73


Weighted average common shares outstanding — basic		153,061			152,022			152,781			151,975

Weighted average common shares outstanding — fully diluted		157,818			158,992			157,905			159,056

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2008			2007
	(Unaudited)
	(Amounts in thousands of U.S. Dollars)
ASSETS
Current assets
Cash and cash equivalents	$	60,344		$	10,632
Restricted cash		2,624			2,590
Accounts receivable		177,409			135,849
Derivative assets		—			5,625
Inventory		6,733			13,333
Prepaid drilling costs and other current assets		2,290			424

Total current assets		249,400			168,453
Oil and gas properties, net, using the full cost method of accounting
Proved		1,866,026			1,537,751
Unproved		36,622			36,778
Property, plant and equipment		4,846			4,739
Deferred financing costs, derivative assets and other		3,063			3,861

Total assets	$	2,159,957		$	1,751,582


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	213,998		$	140,641
Derivative liabilities		54,065			—
Current taxes payable		—			10,839
Capital cost accrual		118,084			88,445

Total current liabilities		386,147			239,925
Long-term debt		300,000			290,000
Deferred income tax liability		376,524			341,406
Other long-term obligations		49,686			26,672
Shareholders’ equity
Share capital		(16,865	)		20,050
Treasury stock		(4,142	)		(59,245	)
Retained earnings		1,104,350			887,820
Accumulated other comprehensive (loss) income		(35,743	)		4,954

Total shareholders’ equity		1,047,600			853,579

Total liabilities and shareholders’ equity	$	2,159,957		$	1,751,582

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended
	June 30,
	2008			2007
	(Unaudited)
	(Amounts in thousands of U.S.
	Dollars)
Cash provided by (used in):
Operating activities:
Net income for the period	$	216,530		$	115,660
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations, net of tax provision of $225 and $8,220, respectively		(415	)		(15,266	)
Depletion and depreciation		85,030			62,221
Deferred income taxes		119,531			53,308
Excess tax benefit from stock based compensation		(62,627	)		(11,548	)
Stock compensation		2,755			2,736
Other		189			43
Net changes in non-cash working capital:
Restricted cash		(34	)		(1,207	)
Accounts receivable		(41,560	)		(14,654	)
Prepaid drilling costs and other current and non-current assets		(1,702	)		(1,006	)
Accounts payable and accrued liabilities		71,124			42,729
Other long-term obligations		20,424			(1,748	)
Current taxes payable		(10,839	)		(2,150	)

Net cash provided by operating activities from continuing operations		398,406			229,118
Net cash provided by operating activities from discontinued operations		—			9,522

Net cash provided by operating activities		398,406			238,640

Investing activities:
Oil and gas property expenditures		(409,089	)		(349,828	)
Investing activities from discontinued operations		—			(10,960	)
Post-closing adjustments on sale of subsidiary		640			—
Change in capital cost accrual		29,639			(9,752	)
Inventory		6,600			5,837
Purchase of capital assets		(461	)		(219	)

Net cash used in investing activities		(372,671	)		(364,922	)

Financing activities:
Borrowings on long-term debt		332,000			135,000
Payments on long-term debt		(322,000	)		—
Deferred financing costs		(1,580	)		(1,082	)
Repurchased shares		(68,635	)		(39,744	)
Excess tax benefit from stock based compensation		62,627			11,548
Stock issued for compensation		4,934			—
Proceeds from exercise of options		16,631			4,867

Net cash provided by financing activities		23,977			110,589

Increase (decrease) in cash during the period		49,712			(15,693	)
Cash and cash equivalents, beginning of period		10,632			14,574

Cash and cash equivalents, end of period	$	60,344		$	(1,119	)

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(All dollar amounts in this Quarterly Report on Form 10-Q are expressed in Thousands of U.S. dollars (except per share data) 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 conducted in the Green River Basin of Southwest Wyoming.

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2007, are unaudited and were prepared from the Company’s records. Balance sheet data as of December 31, 2007 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 through the date of the sale of the China operations. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

(b) Cash and cash equivalents: We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) 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.

(d) Capital assets other than oil and gas properties: Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life.

(e) Oil and natural 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”). Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. 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. The carrying amount of oil and natural 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 natural 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 natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas

reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

Oil and natural 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 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).

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly on a country-by-country basis utilizing prices in effect on the last day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a quarter are the result of a temporary decline and prices improve prior to the issuance of the financial statements, the increased price may be applied in the computation of the ceiling test. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expense in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling. The effect of implementing SFAS No. 143 had no effect on the ceiling test calculation as the future cash outflows associated with settling asset retirement obligations are excluded from this calculation.

(f) Inventories: Materials and supplies inventories are carried at the lower of current market value or cost. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. The Company uses the weighted average method of recording its inventory. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. At June 30, 2008, drilling and completion supplies inventory of $6.7 million primarily includes the cost of pipe and production equipment that will be utilized during the 2008 drilling program.

(g) Forward natural gas sales transactions: The Company primarily relies on fixed price physical delivery contracts, which are considered sales in the normal course of business, to manage its commodity price exposure. The Company, from time to time, also uses derivative instruments as a way to manage its exposure to commodity prices. (See Note 7).

(h) 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. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria of SFAS No. 109.

Effective January 1, 2007, we adopted FASB Interpretation No. 48 (“FIN 48”) which requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

(i) Earnings per share: Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. 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,
	2008		2007		2008		2007
Net income from continuing operations	$	114,756	$	39,752	$	216,115	$	100,394
Net income from discontinued operations	$	482	$	9,317	$	415	$	15,266

Net income	$	115,238	$	49,069	$	216,530	$	115,660

Weighted average common shares outstanding during the period		153,061		152,022		152,781		151,975
Effect of dilutive instruments		4,757		6,970		5,124		7,081

Weighted average common shares outstanding during the period including the effects of dilutive instruments		157,818		158,992		157,905		159,056

Basic Earnings per Share:
Income per common from continuing operations	$	0.75	$	0.26	$	1.41	$	0.66

Income per common from discontinued operations	$	0.00	$	0.06	$	0.00	$	0.10

Net income per common share	$	0.75	$	0.32	$	1.41	$	0.76

Fully Diluted Earnings per Share:
Income per common from continuing operations	$	0.73	$	0.25	$	1.37	$	0.63

Income per common from discontinued operations	$	0.00	$	0.06	$	0.00	$	0.10

Net income per common share	$	0.73	$	0.31	$	1.37	$	0.73

(j) Use of estimates: Preparation of consolidated financial statements in accordance with 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) Accounting for share-based compensation: The Company applies Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options based on estimated fair values. Share-based compensation expense recognized under SFAS No. 123R for the six months ended June 30, 2008 and 2007 was $2.8 million and $2.7 million, respectively. See Note 4 for additional information.

(l) Fair Value Accounting. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurements. The changes to current practice resulting from the application of this statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements. The Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. For those non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, SFAS No. 157 is effective January 1, 2009. Implementation of this portion of the standard is not expected to have a material impact on consolidated results of operations, financial position or liquidity. See Note 9 for additional information.

(m) Revenue Recognition. Natural gas revenues are recorded based on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company initially 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 immediately 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.

(n) Other Comprehensive Income: Other comprehensive income is a term used to define revenues, expenses, gains and losses that under generally accepted accounting principles impact Shareholders’ Equity, excluding transactions with shareholders.


	For the three months ended						For the six months ended
	June 30,						June 30,
	2008			2007			2008			2007
Net income	$	115,238		$	49,069		$	216,530		$	115,660
Unrealized gain (loss) on derivative instruments		(5,116	)		3,028			(55,074	)		3,028
Taxes benefit (expense) on unrealized gain (loss) on derivative instruments		1,796			(1,063	)		19,331			(1,063	)

Other comprehensive income	$	111,918		$	51,034		$	180,787		$	117,625

At June 30, 2008, the Company recorded a non-current asset of $1.1 million, a current liability of $54.1 million and a non-current liability of $2.1 million associated with the derivative instruments included in other comprehensive income.

(o) Reclassifications: Certain amounts in the financial statements of the prior periods have been reclassified to conform to the current period financial statement presentation. (Refer to Note 8).

(p) Impact of recently issued accounting pronouncements: In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to increase transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133; and how derivative instruments and related hedged items affect financial position, financial performance, and cash flows. SFAS No. 161 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2008. The Company does not anticipate that the implementation of SFAS No. 161 will have a material impact on the consolidated results of operations, financial position or liquidity.

2. OIL AND GAS PROPERTIES:


	June 30,			December 31,
	2008			2007
Developed Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	2,281,171		$	1,868,564
Less accumulated depletion, depreciation and amortization		(415,145	)		(330,813	)

		1,866,026			1,537,751

Unproven Properties:
Acquisition and exploration costs		36,622			36,778

	$	1,902,648		$	1,574,529

3. LONG-TERM LIABILITIES:


	June 30,		December 31,
	2008		2007
Bank indebtedness	$	—	$	290,000
Senior notes, due 2015		100,000		—
Senior notes, due 2018		200,000		—
Other long-term obligations		49,686		26,672

	$	349,686	$	316,672

Bank indebtedness: The Company (through its subsidiary) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012. This agreement provides an initial loan commitment of $500.0 million and may be increased to a maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right, but not the obligation, to increase the amount of its commitment as requested by the Company. In the event the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to add new financial institutions to the credit facility.

Loans under the credit facility are unsecured and bear interest, at our option, based on (A) a rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 50 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of our consolidated leverage ratio (87.5 basis points per annum as of June 30, 2008).

At June 30, 2008, we had no outstanding borrowings and $500.0 million of available borrowing capacity under our credit facility.

The facility has restrictive covenants that include the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to exceed 3¹/2 times; and as long as our debt rating is below investment grade, the maintenance of an annual ratio of the net present value of our oil and gas properties to total funded debt of at least 1.75 to 1.00. At June 30, 2008, we were in compliance with all of our debt covenants under our credit facility.

Senior Notes, due 2015 and 2018: On March 6, 2008, our wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes (“the Notes”) pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the Company’s bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are 5.45% Senior Notes due 2015.

Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the borrowings available to us under the revolving credit facility.

The Notes are pre-payable in whole or in part at any time. The Notes are subject to representations, warranties, covenants and events of default customary for a senior note financing. If payment default occurs, any Note holder may accelerate its Notes; if a non-payment default occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the Notes. At June 30, 2008, we were in compliance with all of our debt covenants under the Notes.

Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable, a liability associated with imbalanced production, the long-term portion of costs associated with our compensation programs and our asset retirement obligations.

4. SHARE BASED COMPENSATION:

Valuation and Expense Information under SFAS 123R

The following table summarizes share-based compensation expense under SFAS No. 123R for the six months ended June 30, 2008 and 2007, respectively, which was allocated as follows:


	Six Months Ended June 30,
	2008		2007
Total cost of share-based payment plans	$	4,866	$	4,649
Amounts capitalized in fixed assets	$	2,111	$	1,913
Amounts charged against income, before income tax benefit	$	2,755	$	2,736
Amount of related income tax benefit recognized in income	$	967	$	977

The fair value of each share option award is estimated on the date of grant using a Black-Scholes pricing model based on assumptions noted in the following table. The Company’s employee stock options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and are often exercised prior to their contractual maturity. Expected volatilities used in the fair value estimate are based on historical volatility of the Company’s stock. The Company uses historical data to estimate share option exercises, expected term and employee departure behavior used in the Black-Scholes pricing model. Groups of employees (executives and non-executives) that have similar historical behavior are considered separately for purposes of determining the expected term used to estimate fair value. The assumptions utilized result from differing pre- and post-

vesting behaviors among executive and non-executive groups. The risk-free rate for periods within the contractual term of the share option is based on the U.S. Treasury yield curve in effect at the time of grant.


	Six Months Ended
	June 30, 2008						June 30, 2007
	Non-Executives			Executives			Non-Executives			Executives
Expected volatility		41.22 - 42.47	%		42.5	%		42.54 - 43.70	%		44.40	%
Expected dividends		0	%		0	%		0	%		0	%
Expected term (in years)		5.01 - 5.08			5.98			4.75 - 5.02			5.53
Risk free rate		2.48 - 3.41	%		2.98	%		4.52 - 5.07	%		4.69	%
Expected forfeiture rate		15.0	%		15.0	%		14.0	%		14.0	%

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the six months ended June 30, 2008:


				Weighted
				Average
	Number of			Exercise Price
	Options			(US$)
Balance, December 31, 2007		7,589		$0.25 to $67.73

Granted		183		$71.72 to $87.59
Exercised		(2,325	)	$0.25 to $67.73

Balance, June 30, 2008		5,447		$0.25 to $87.59

PERFORMANCE SHARE PLANS:

Long-Term Equity-Based Incentives. In 2005, we adopted the Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and give key employees the opportunity to share in the long-term performance of the Company by achieving specific corporate financial and operational goals. Participants are recommended by the CEO and approved by the Compensation Committee. Selected officers, managers and other key employees are eligible to participate in the LTIP which has two components, an LTIP Stock Option Award and an LTIP Common Stock Award.

Under the LTIP, each year the Compensation Committee establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary to derive an LTI Value (“Long Term Incentive Value”). With respect to LTIP Stock Option Awards, options are awarded equal to one half of the LTI Value based on the fair value on the date of grant (using Black-Scholes methodology).

The other half of the LTI Value is the “target” amount that may be awarded to the participant as an LTIP Common Stock Award at the end of a three year performance period. The Compensation Committee establishes performance measures at the beginning of each three year overlapping performance period. Each participant is also assigned threshold and maximum award levels in the event that performance is below or above target levels. Awards are expressed as dollar targets and become payable in common shares at the end of each performance period based on the Company’s overall performance during such period. A new three year period begins each January. Participants must be employed by the Company when an award is distributed in order to receive an award.

For the performance periods January 2006 — December 2008 (“2006 LTIP”), January 2007 — December 2009 (“2007 LTIP”), and January 2008 — 2010 (“2008 LTIP”), the Compensation Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

For the six months ended June 30, 2008, the Company recognized $0.3 million, $0.4 million and $0.3 million in pre-tax compensation expense related to the 2006 LTIP, 2007 LTIP and 2008 LTIP, respectively. For the six months ended June 30, 2007, the Company recognized $0.3 million and $0.3 million in pre-tax compensation expense related to the 2006 LTIP and 2007 LTIP, respectively. The amounts recognized during the first six months of 2008 and 2007 assume that maximum performance objectives are attained. If the Company ultimately attains maximum performance objectives, the associated total compensation cost, estimated at

June 30, 2008, for the three year performance periods would be approximately $2.6 million, $3.3 million and $3.1 million (before taxes) related to the 2006 LTIP, 2007 LTIP and 2008 LTIP, respectively.

In 2008, the Company established the second performance period for the Best in Class program for all employees. The first performance period ended December 31, 2007 with the resulting payout in the second quarter of 2008. The Best in Class program recognizes and financially rewards the collective efforts of all of our employees in achieving sustained industry leading performance and the enhancement of shareholder value. Under the Best in Class program, on January 1, 2008 or the employment date if subsequent to January 1, 2008, all employees received a contingent award of stock units equal to $60,000 worth of our common stock based on the average high and low share price on the date of grant. Employees joining the Company after January 1, 2008 will participate on a pro rata basis based on their length of employment during the performance period. The number of units that will vest and become payable is based on our performance relative to the industry during a three-year performance period beginning January 1, 2008, and ending December 31, 2010, and are set at threshold (50%), target (100%) and maximum (150%) levels. For each vested unit, the participant will receive one share of common stock. The performance measures are all sources finding and development cost and full cycle economics.

For the six months ended June 30, 2008, the Company recognized $0.3 million in pre-tax compensation expense related to the Best in Class program. For the six months ended June 30, 2007, the Company recognized $0.3 million in pre-tax compensation expense related to the first performance period of the Best in Class program. The amount recognized for the six months ended June 30, 2008 assumes that target performance levels are achieved. If the Company ultimately attains the target performance level, the associated total compensation cost will be approximately $3.0 million before income taxes.

5. SHARE REPURCHASE PROGRAM:

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate $1 billion of the Company’s outstanding common stock which has been and will be funded by cash on hand and the Company’s senior credit facility. Pursuant to this authorization, the Company has commenced a program to purchase up to $500.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions. The stock repurchase will be funded with cash held in an Ultra Resources bank account or the Company’s senior credit facility.

The following tables summarize the Company’s share repurchases in total (open market repurchases plus net share settlements) as of June 30, 2008:


	Shares		Weighted Average
TOTAL	Purchased		Price per Share		$ Value
1st Quarter — 2008		397	$	75.25	$	29,829
2nd Quarter — 2008		452	$	85.97	$	38,807
Prior		5,694	$	51.73	$	294,549

May 2006 — June 30, 2008		6,543	$	55.52	$	363,185


	Shares		Weighted Average
OPEN MARKET	Purchased		Price per Share		$ Value
1st Quarter — 2008		214	$	75.53	$	16,139
2nd Quarter — 2008		210	$	84.13	$	17,643
Prior		5,401	$	51.19	$	276,442

May 2006 — June 30, 2008		5,825	$	53.27	$	310,224


	Shares		Weighted Average
NET SHARE SETTLEMENTS	Purchased		Price per Share		$ Value
1st Quarter — 2008		183	$	74.92	$	13,690
2nd Quarter — 2008		242	$	87.57	$	21,164
Prior		293	$	61.73	$	18,107

May 2006 — June 30, 2008		718	$	73.79	$	52,961

Subsequent to June 30, 2008 and through July 31, 2008, the Company has repurchased $67.8 million of its outstanding common stock in open market repurchases or net share settlements.

6. INCOME TAXES:

The amount of unrecognized tax benefits did not materially change as of June 30, 2008. It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, Ultra does not expect the change to have a significant impact on the results of operations or the financial position of the Company. Interest expense or penalties recognized during the six months ended June 30, 2008 were immaterial.

Ultra’s effective tax rate is 35.6% for the six months ended June 30, 2008 and 35.8% for the same period in 2007.

7. DERIVATIVE FINANCIAL INSTRUMENTS:

The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural gas prices are derived from the financial statements which include the effects of hedging and natural gas balancing.

The Company primarily relies on fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales. The Company, from time to time, also uses derivative instruments to manage its exposure to commodity prices. The Company has periodically entered into fixed price to index price swap agreements in order to hedge a portion of its natural gas production. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by such publications as Inside FERC Gas Market Report. Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. At June 30, 2008, all hedges were considered effective as the hedging instruments offset the change in the hedged transaction’s cash flows for the risk being hedged. 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 (loss) income 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 cash flow hedges.

The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming delivery points to hedge its commodity price exposure. The Company had the following fixed price physical delivery contracts in place on behalf of its interest and those of other parties at June 30, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program which had the effect of increasing the Company’s average net interest in physical gas sales from 80% to approximately 91%.)


	Volume-		Average
Remaining Contract Period	MMBTU/Day		Price/MMBTU
Calendar 2008		100,000	$	6.83
Summer 2008 (July — October)		20,000	$	6.88
Calendar 2009		10,000	$	7.51
Summer 2009 (April — October)		90,000	$	7.06

At June 30, 2008, the Company had the following open commodity 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 NWPL Rockies basis).


		Volume-		Average		Unrealized
		MMBTU/		Price/		Loss (000’s) at
Type	Remaining Contract Period	Day		MMBTU		6/30/2008*
Swap	July 2008 — Oct 2008		190,000	$	7.19	$	(40,801	)
Swap	Jan 2009 — Dec 2009		30,000	$	7.35	$	(14,273	)


*		Unrealized losses are not adjusted for income tax effect.

For the six months ended June 30, 2008, the Company recognized costs associated with financially settled swaps to counterparties totaling $24.2 million as its net realization from hedging activities, which was recognized as a reduction of natural gas sales on the income statement.

8. DISCONTINUED OPERATIONS:

During the third quarter of 2007, we made the decision to dispose of Sino-American Energy Corporation, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in the Pinedale Field in southwest Wyoming. The reserve volumes sold represent all of Ultra’s international assets and, previously, were the only results included in our foreign operating segment.

On September 26, 2007, our wholly-owned subsidiary, UP Energy Corporation, a Nevada corporation, entered into a definitive share purchase agreement with an effective date of June 30, 2007 and a closing date of October 22, 2007 in order to sell all of the outstanding shares of Sino-American Energy Corporation (“Sino-American”), a Texas corporation, for a total purchase price of US$223.0 million, subject to adjustments. The Company recorded results of operations for the China properties through the close date of October 22, 2007.

The Company has accounted for its Sino-American operations as discontinued operations and has reclassified prior period financial statements to exclude these businesses from continuing operations. A summary of financial information related to the Company’s discontinued operations is as follows:


	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2008		2007		2008		2007
Operating revenues	$	—	$	25,951	$	—	$	45,568
Post closing adjustment on sale of subsidiary		743		—		640		—
Operating expenses		—		12,399		—		22,082

Income before income tax provision		743		13,552		640		23,486
Income tax provision		261		4,235		225		8,220

Income from discontinued operations, net of tax	$	482	$	9,317	$	415	$	15,266

9. FAIR VALUE MEASUREMENTS:

On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurement”. We adopted SFAS No. 157 effective January 1, 2008. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. The statement requires fair value measurements be classified and disclosed in one of the following categories:


Level 1:		Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

Level 2:		Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3:		Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

The valuation assumptions utilized to measure the fair value of the Company’s cash flow hedges were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

The following table presents for each hierarchy level our assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis, as of June 30, 2008:


	Level 1		Level 2		Level 3		Total
Assets:
Derivatives	$	—	$	1,071	$	—	$	1,071
Liabilities:
Derivatives	$	—	$	56,145	$	—	$	56,145

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The derivative transactions are placed with major financial institutions or with counterparties of high credit quality that present minimal credit risks to the Company. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

10. 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 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company. Except as otherwise indicated all amounts are expressed in U.S. Dollars. We operate in one industry segment, natural gas and oil exploration and development with one geographical segment; the United States. (See Note 8 for a discussion regarding the sale of our Chinese assets).

The Company currently generates substantially all of its revenue, earnings and cash from the production and sales of natural gas and oil from its property in southwest 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 realizations for the period 2003-2008 have ranged from $2.33 to $8.64 per Mcf. This volatility could be detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into fixed price forward physical delivery contracts

and swap agreements for gas in southwest Wyoming. During the quarter ended June 30, 2008, the average price realization for the Company’s natural gas was $8.06 per Mcf, including the effects of hedging. The Company’s average price realization for natural gas was $8.80 per Mcf, excluding the effects of hedging.

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. The Company delivered 23% production growth from continuing operations on an Mcfe basis during the quarter ended June 30, 2008 as compared to the same quarter in 2007.

Rockies Express Pipeline. In December 2005, the Company agreed to become an anchor shipper on the Rockies Express Pipeline (“REX”) securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. The Company’s commitment involves capacity of 200,000 MMBtu per day of natural gas for a term of 10 years (beginning in the first quarter of 2008), and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The pipeline will be completed in two (2) phases: REX — West (Wyoming to Missouri) and REX — East (Missouri to Ohio).

During the quarter ended June 30, 2008, the REX — West pipeline was extended from the ANR delivery point in Brown County, Kansas to the Panhandle Eastern Pipeline system at Audrain County, Missouri and placed into service. With the completion of this segment, the Company is able to deliver its firm capacity of 200,000 MMBtu per day of natural gas from Wyoming to markets in the mid-west.

On May 30, 2008, the FERC issued a Certificate of Public Convenience and Necessity for the REX — East project. Kinder Morgan, the managing member of REX, has indicated that the current schedule anticipates REX — East to be operational by the end of 2008 to pipeline interconnections near Lebannon, Ohio. Kinder Morgan has further advised that, when fully completed, (estimated to be Mid-Year 2009) the REX — East pipeline will provide up to 1.8 Bcf per day of natural gas transportation capacity from the Rockies to Clarington, Ohio.

Discontinued Operations. On September 27, 2007, the Company announced the execution of a stock purchase agreement for the sale of Sino-American Energy Corporation which represents all of Ultra’s interest in Bohai Bay, China for $223 million. Despite having owned Sino-American in the first half of 2007, under generally accepted accounting principles (“GAAP”), its operations have been reclassified as “Discontinued Operations” for the entire quarter. As a result, production, revenues and expenses associated with Sino-American have been removed from continuing operations and reclassified to discontinued operations. The sale closed on October 22, 2007, with an effective date of June 30, 2007.

Fair Value Measurements. The Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. See Note 9 for additional information.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s cash flow hedges were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The derivative transactions are placed with major financial institutions or with counter-parties of high credit quality, which in the Company’s opinion, present minimal credit risks to the Company. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

The fair values summarized below were determined in accordance with the requirements of SFAS No. 157. In addition, we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by SFAS No. 157. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments at June 30, 2008 is summarized in the following table based on the inputs used to determine fair value:


	Level 1(a)		Level 2(b)		Level 3(c)		Total
Assets:
Derivatives	$	—	$	1,071	$	—	$	1,071
Liabilities:
Derivatives	$	—	$	56,145	$	—	$	56,145


(a)		Values represent observable unadjusted quoted prices for traded instruments in active markets.

(b)		Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.

(c)		Values with a significant amount of inputs that are not observable for the instrument.

Share-Based Payment Arrangements. The Company applies Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized under SFAS No. 123R for the six months ended June 30, 2008 and 2007 was $2.8 million and $2.7 million, respectively. At June 30, 2008, there was $11.2 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under stock option plans. That cost is expected to be recognized over a weighted average period of 1.9 years. See Note 4 for additional information.

SFAS No. 123R requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The Company utilized a Black-Scholes option pricing model to measure the fair value of stock options granted to employees. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in the Company’s Consolidated Statement of Operations. The Company’s determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the Company’s stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to the Company’s expected stock price volatility over the term of the awards and actual and projected employee stock option exercise behaviors.

Full Cost Method of Accounting. 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 on a country-by-country basis. 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. 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. Inflation has not had a material impact on the Company’s results of operations and is not expected to have a material impact on the Company’s results of operations in the future.

A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.

RESULTS OF OPERATIONS

QUARTER ENDED JUNE 30, 2008 VS. QUARTER ENDED JUNE 30, 2007

During the second quarter of 2008, production from continuing operations increased 23% on a gas equivalent basis to 34.3 Bcfe from 27.9 Bcfe for the same quarter in 2007 attributable to the Company’s successful drilling activities during 2007 and in the first six months of 2008. Realized natural gas prices, including the effect of hedging, increased 84% to $8.06 per Mcf in the second quarter of 2008 as compared to $4.38 for the second quarter of 2007. The increase in realized average natural gas prices together with the increase in production contributed to a 125% increase in revenues from continuing operations to $294.1 million as compared to $130.9 million in 2007.

Lease operating expense (“LOE”) increased to $8.6 million at June 30, 2008 compared to $5.6 million at June 30, 2007 due primarily to increased production volumes. On a unit of production basis, LOE costs increased to $0.25 per Mcfe at June 30, 2008 compared to $0.20 per Mcfe at June 30, 2007 mainly due to costs related to non-operated properties for water disposal expenses.

During the second quarter of 2008, production taxes were $35.8 million compared to $14.7 million during the second quarter of 2007, or $1.04 per Mcfe (12.2% of revenues), compared to $0.53 per Mcfe (11.2% of revenues). The increase in per unit taxes is attributable to increased sales revenues as a result of increased production and higher realized gas prices received during the quarter ended June 30, 2008 as compared to the same period in 2007. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased production taxes on a per unit basis.

Gathering fees increased to $8.8 million at June 30, 2008 compared to $7.0 million at June 30, 2007 largely due to increased production volumes. On a per unit basis, gathering fees remained relatively flat at $0.26 per Mcfe for the three months ended June 30, 2008 as compared to $0.25 per Mcfe for the same period in 2007.

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred transportation demand charges totaling $12.0 million for the quarter ended June 30, 2008 in association with REX Pipeline demand charges.

Depletion, depreciation and amortization (“DD&A”) expenses increased to $42.8 million during the quarter ended June 30, 2008 from $32.6 million for the same period in 2007, attributable to increased production volumes and a higher depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.25 per Mcfe at June 30, 2008 from $1.17 at June 30, 2007.

General and administrative expenses increased to $4.4 million ($0.13 per Mcfe) at June 30, 2008 compared to $3.4 million ($0.12 per Mcfe) for the same period in 2007. The increase in general and administrative expenses during 2008 is primarily attributable to increased Medicare taxes as a result of increased employee stock option exercises during the quarter months ended June 30, 2008.

Interest expense remained relatively flat at $4.5 million during the quarter ended June 30, 2008 compared to $4.2 million during the same period in 2007. At June 30, 2008 and 2007, the Company had $300.0 million in borrowings outstanding.

Net income before income taxes increased to $177.4 million for the quarter ended June 30, 2008 from $63.7 million for the same period in 2007 primarily as a result of increased natural gas prices and increased production during the quarter ended June 30, 2008.

The income tax provision increased to $62.6 million for the three months ended June 30, 2008 as compared to $23.9 million for the three months ended June 30, 2007 due to higher pre-tax income.

Income from discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese assets) decreased to $0.5 million for the quarter ended June 30, 2008 from $9.3 million for the same period in 2007. The sale closed on October 22, 2007. See Note 8 for additional information.

For the quarter ended June 30, 2008, net income increased to $115.2 million or $0.73 per diluted share as compared with $49.1 million or $0.31 per diluted share for the same period in 2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural gas production.

SIX MONTHS ENDED JUNE 30, 2008 VS. SIX MONTHS ENDED JUNE 30, 2007

During the six months ended June 30, 2008, production from continuing operations increased 27% on a gas equivalent basis to 68.4 Bcfe from 53.9 Bcfe for the same period in 2007 attributable to the Company’s successful drilling activities during 2007 and in the first six months of 2008. Realized natural gas prices, including the effect of hedging, increased 53% to $7.86 per Mcf for the six months ended June 30, 2008 as compared to $5.13 for the same period in 2007. The increase in realized average natural gas prices together with the increase in production contributed to a 97% increase in revenues from continuing operations to $565.3 million as compared to $287.4 million in 2007.

LOE increased to $19.3 million at June 30, 2008 compared to $10.3 million at June 30, 2007 due primarily to increased production volumes. On a unit of production basis, LOE costs increased to $0.28 per Mcfe at June 30, 2008 compared to $0.19 per Mcfe at June 30, 2007 mainly due to costs related to non-operated properties for water disposal expenses.

During the first half of 2008, production taxes were $66.7 million compared to $32.2 million during the same period of 2007, or $0.98 per Mcfe (11.8% of revenues), compared to $0.60 per Mcfe (11.2% of revenues). The increase in per unit taxes is attributable to increased sales revenues as a result of increased production and higher realized gas prices received during the six months ended June 30, 2008 as compared to the same period in 2007. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased production taxes on a per unit basis.

Gathering fees increased to $18.8 million at June 30, 2008 compared to $13.5 million at June 30, 2007 largely due to increased production volumes. On a per unit basis, gathering fees increased to $0.27 per Mcfe for the six months ended June 30, 2008 as compared to $0.25 per Mcfe for the same period in 2007.

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred transportation demand charges totaling $21.7 million for the six months ended June 30, 2008 in association with the REX Pipeline demand charges.

DD&A expenses increased to $85.0 million during the six months ended June 30, 2008 from $62.2 million for the same period in 2007, attributable to increased production volumes and a higher depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.24 per Mcfe at June 30, 2008 from $1.15 at June 30, 2007.

General and administrative expenses increased to $8.8 million ($0.13 per Mcfe) at June 30, 2008 compared to $6.6 million ($0.12 per Mcfe) for the same period in 2007. The increase in general and administrative expenses during 2008 is primarily attributable to increased Medicare taxes as a result of increased employee stock option exercises during the six months ended June 30, 2008.

Interest expense increased to $9.8 million during the six months ended June 30, 2008 from $6.9 million during the same period in 2007. The increase is related to higher average outstanding debt balances during the period ended June 30, 2008 as compared to the same period in 2007. At June 30, 2008 and 2007, the Company had $300.0 million in borrowings outstanding.

Net income before income taxes increased to $335.5 million for the six months ended June 30, 2008 from $156.4 million for the same period in 2007 primarily as a result of increased natural gas prices and increased production during the six months ended June 30, 2008.

The income tax provision increased to $119.3 million for the six months ended June 30, 2008 as compared to $56.0 million for the six months ended June 30, 2007 due to higher pre-tax income.

Income from discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese assets) decreased to $0.4 million for the six months ended June 30, 2008 from $15.3 million for the same period in 2007. The sale closed on October 22, 2007. See Note 8 for additional information.

For the six months ended June 30, 2008, net income increased to $216.5 million or $1.37 per diluted share as compared with $115.7 million or $0.73 per diluted share for the same period in 2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural gas production.

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

LIQUIDITY AND CAPITAL RESOURCES

During the six month period ended June 30, 2008, the Company relied on cash provided by operations along with borrowings under the senior credit facility and the issuance of the Notes to finance its capital expenditures. The Company participated in the drilling of 190 wells in Wyoming. For the six month period ended June 30, 2008, net capital expenditures were $409.1 million. At June 30, 2008, the Company reported a cash position of $60.3 million compared to a cash deficit of $1.1 million at June 30, 2007. Working capital at June 30, 2008 was a deficit of $136.7 million compared to working capital of $34.1 million at June 30, 2007. As of June 30, 2008, the Company had no bank indebtedness outstanding and $500.0 million of available borrowing capacity under its facility. Other long-term obligations of $49.7 million at June 30, 2008 is 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 availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2008, which are currently projected to be $945.0 million. Of the $945.0 million budget, the Company plans to allocate approximately 97% to Wyoming and 3% to Pennsylvania.

Bank indebtedness. The Company (through its subsidiary) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012. This agreement provides an initial loan commitment of $500.0 million and may be increased to a maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right, but not the obligation, to increase the amount of its commitment as requested by the Company. In the event the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to add new financial institutions to the credit facility.

Senior Notes, due 2015 and 2018: On March 6, 2008, our wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the Company’s bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are 5.45% Senior Notes due 2015.

Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the borrowing available to us under our revolving credit facility.

payment default occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the Notes. At June 30, 2008, we were in compliance with all of our debt covenants under the Notes.

Operating Activities. During the six months ended June 30, 2008, net cash provided by operating activities was $398.4 million, a 67% increase over the $238.6 million for the same period in 2007. The increase in net cash provided by operating activities was largely attributable to the increase in production and realized natural gas prices during the six months ended June 30, 2008 as compared to the same period in 2007.

Investing Activities. During the six months ended June 30, 2008, net cash used in investing activities was $372.7 million as compared to $364.9 million for the same period in 2007. The increase in net cash used in investing activities is largely due to increased capital expenditures associated with the Company’s drilling activities in 2008.

Financing Activities. During the six months ended June 30, 2008, net cash provided by financing activities was $24.0 million as compared to $110.6 million for the same period in 2007. The decrease in cash provided by net financing activities is primarily attributable to decreased net borrowings during the six months ended June 30, 2008 as compared to the same period in 2007.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of June 30, 2008.

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, 2007 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 natural gas production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural gas prices are derived from the financial statements which include the effects of hedging and natural gas balancing.

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. At June 30, 2008, all hedges were considered effective as the hedging instruments offset the change in the hedged transaction’s cash flows for the risk being hedged. 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 (loss) income 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 cash flow hedges.

On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurement”. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s cash flow hedges were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The derivative transactions are placed with major financial institutions or with counterparties of high credit quality that present minimal credit risks to the Company. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.


	Volume-		Average
Remaining Contract Period	MMBTU/Day		Price/MMBTU
Calendar 2008		100,000	$	6.83
Summer 2008 (July — October)		20,000	$	6.88
Calendar 2009		10,000	$	7.51
Summer 2009 (April — October)		90,000	$	7.06


		Volume-		Average		Unrealized
		MMBTU/		Price/		Loss (000’s) at
Type	Remaining Contract Period	Day		MMBTU		6/30/2008*
Swap	July 2008 — Oct 2008		190,000	$	7.19	$	(40,801	)
Swap	Jan 2009 — Dec 2009		30,000	$	7.35	$	(14,273	)


*		Unrealized losses are not adjusted for income tax effect.

ITEM 4 — CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of June 30, 2008. There were no changes in our internal control over financial reporting during the six months ended June 30, 2008 that have materially affected or are reasonably likely to affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $1 billion of the Company’s outstanding common stock which has been and will be funded by cash on hand and borrowings under the Company’s senior credit facility. Pursuant to this authorization, the Company has commenced a program to purchase up to $500.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions. (See Note 5 for further details).


					Total Number		Maximum Number
					of Shares		(or Approximate
					Purchased		Dollar Value)
					as Part of		of Shares That
					Publicly		May Yet be
	Total Number		Average		Announced		Purchased
	of Shares		Price Paid		Plans or		Under the
Period	Purchased		per Share		Programs		Plans or Programs
Jan 1 — Jan 31, 2008		96,321	$	71.57		96,321	$699 million
Feb 1 — Feb 28, 2008		71,281	$	79.04		71,281	$693 million
Mar 1 — Mar 31, 2008		228,830	$	75.61		228,830	$676 million
Apr 1 — Apr 30, 2008		223,559	$	79.51		223,559	$658 million
May 1 — May 31, 2008		45,668	$	90.07		45,668	$654 million
Jun 1 — Jun 30, 2008		182,153	$	92.88		182,153	$637 million

TOTAL		847,812	$	80.96		847,812	$637 million

Subsequent to June 30, 2008 and through July 31, 2008, the Company has repurchased $67.8 million of its outstanding common stock in open market repurchases or net share settlements.

ITEM 3. DEFAULTS IN SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS

The Company held its annual meeting on May 16, 2008. 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	–	134,031,245 voted in favor, zero voted against and 839,676 withheld.

W. Charles Helton	–	134,499,794 voted in favor, zero voted against and 371,127 withheld.

Stephen J. McDaniel	–	133,826,892 voted in favor, zero voted against and 1,044,029 withheld.

Roger A. Brown	–	133,828,182 voted in favor, zero voted against and 1,042,739 withheld.

Robert E. Rigney	–	134,542,847 voted in favor, zero voted against and 328,074 withheld.

The shareholders of the Company approved the appointment of Ernst & Young, LLP as the Company’s independent auditors for 2008. There were 134,582,266 votes in favor of approval of the appointment of Ernst & Young, LLP as the Company’s auditors, zero votes against and 288,654 votes withheld.

The shareholders of the Company voted against the shareholder proposal regarding climate change with 67,584,431 votes against, 38,958,528 votes in favor of the proposal and 28,327,962 Broker Non-votes.

A total of 134,870,921 shares were voted by 221 shareholders, representing 88% of the Company’s outstanding shares.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K -

(a) Exhibits


3.1		Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 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.)

3.3		Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005)

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		Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008).

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		filed herewith

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.
By:	/s/ Michael D. Watford
	Name:	Michael D. Watford
	Title:	Chairman, President and Chief Executive Officer

Date: August 6, 2008



By:	/s/ Marshall D. Smith
	Name:	Marshall D. Smith
	Title:	Chief Financial Officer

Date: August 6, 2008

EXHIBIT INDEX


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.)

3.3		Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005)

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		Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008).

31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		filed herewith

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