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.

The Company currently generates substantially all of its revenue, earnings and cash flow 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 2003-2009 have ranged from $2.33 to $8.81 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 March 31, 2009, the average price realization for the Company's natural gas was $4.46 per Mcf, including realized gain or loss on commodity derivatives. The Company's average price realization for natural gas was $3.95 per Mcf, excluding the realized gain or loss on commodity derivatives. (See Note 6).

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 24% production growth on an Mcfe basis during the quarter ended March 31, 2009 as compared to the same quarter in 2008.

The Company currently conducts operations exclusively in the United States. Substantially all of the oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented 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.

In 2008 and the first quarter of 2009, we saw significant changes in the business environment in which we operate, including severe economic uncertainty, increasing market volatility and continued tightening of credit markets. These market conditions contributed to record high commodity prices during most of 2008 and nearly unprecedented drops in these commodity prices in the second half of 2008 and the first quarter of 2009. We believe we are well positioned to weather the current economic downturn because of our status as a low cost operator in the industry and our financial flexibility. Although we expect that our net cash provided by operating activities may be negatively affected by general economic conditions, we believe that we will continue to generate strong cash flow from operations, which, along with our available cash, will provide sufficient liquidity to allow us to return value to our shareholders. While it is possible that we may not have access to the credit markets on acceptable terms, we expect to rely on our available cash, our existing credit facility and the cash we generate from our operations to meet our obligations and fund our capital expenditures and operations over the next twelve months. A continued, long-term disruption in the credit markets could make financing more expensive or unavailable, which could have a material adverse effect on our operations.

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 our natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for our 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 when REX - West became operational), 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 is being built in two phases: REX - West (Wyoming to Missouri - in service) and REX - East (Missouri to Ohio - under construction). The REX partners have recently updated guidance on the timing for completion of various portions of REX - East. As of April 2009, REX projects it will initially commence REX - East service to five delivery points in Illinois (NGPL, Ameren, Trunkline, Midwestern and PEPL) by the end of

May 2009. REX also confirmed its previously projected in-service dates for an additional 169 miles of pipeline and an additional nine pipeline interconnections in Indiana and western Ohio will be placed into service on or around June 15, 2009. Kinder Morgan further advised that the balance of the REX - East pipeline will be available to be placed into service by November 1, 2009.

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. The sale closed on October 22, 2007, with an effective date of June 30, 2007. The Company accounted for its Sino-American operations as discontinued operations.

Derivative Instruments and Hedging Activities. The Company relies on derivative instruments to manage its exposure to commodity price risk. The Company enters into fixed price to index price swap agreements in order to mitigate its commodity price exposure on 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 independent third parties. The Company also utilizes fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of SFAS No. 133.

Effective November 3, 2008, the Company has changed its method of accounting for natural gas commodity derivatives to reflect unrealized gains and losses on commodity derivative contracts in the income statement rather than on the balance sheet. The Company has historically followed hedge accounting for its natural gas hedges. Under this accounting method, the unrealized gain or loss on qualifying cash flow hedges (calculated on a mark to market basis, net of tax) was recorded on the balance sheet in stockholders' equity as accumulated other comprehensive income (loss). When an unrealized hedging gain or loss was realized upon contract expiration, it was reclassified into earnings through inclusion in natural gas sales revenues. The Company will continue to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but will record the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. There will be no resulting effect on overall cash flow, total assets, total liabilities or total stockholders' equity, and there is no impact on any of the financial covenants under the Company's Senior Credit Facility, 2008 Senior Notes or 2009 Senior Notes.

During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were converted at no cost to the Company and the conversion of these contracts to derivative instruments was effective upon entering into these transactions in March 2009, with upcoming settlements for production months from April 2009 through December 2010.

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 7 for additional information. For those non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, primarily asset retirement obligations, SFAS No. 157-2 was effective January 1, 2009. Implementation of this portion of the standard did not have a material impact on consolidated results of operations, financial position or liquidity.

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 commodity derivatives 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. 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 March 31, 2009 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:
Current derivative asset           $         -     $    212,874     $         -     $ 212,874
Non-current derivative asset       $         -     $      8,953     $         -     $   8,953
Liabilities:
Current derivative liability       $         -     $        151     $         -     $     151
Non-current derivative liability   $         -     $      2,792     $         -     $   2,792

(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.

Asset Retirement Obligation. The initial estimated retirement obligation of properties is recognized as a liability, with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

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 three months ended March 31, 2009 and 2008 was $2.1 million and $0.9 million, respectively. At March 31, 2009, there was $8.5 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 1.3 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 period 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.

Write-down of oil and gas properties. The Company uses the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration for and development of oil and gas reserves are capitalized 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.

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 Company recorded a $1.0 billion ($673.0 million net of tax) non-cash write-down of the carrying value of the Company's proved oil and gas properties as of March 31, 2009, as a result of the ceiling test limitations, which is reflected as write-down of oil and gas properties in the accompanying consolidated statements of operations. The ceiling test was calculated based on March 31, 2009 wellhead prices of $2.47 per Mcf for natural gas and $33.91 per barrel for condensate. If oil and gas prices continue to decline below those at March 31, 2009, additional write-downs of oil and gas properties are likely to occur.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

RESULTS OF OPERATIONS

QUARTER ENDED MARCH 31, 2009 VS. QUARTER ENDED MARCH 31, 2008

During the first quarter of 2009, production increased 24% on a gas equivalent basis to 42.1 Bcfe from 34.1 Bcfe for the same quarter in 2008 attributable to the Company's successful drilling activities during 2008 and in the first three months of 2009. Realized natural gas prices, including realized gain and loss on commodity derivatives, decreased 42% to $4.46 per Mcf in the first quarter of 2009 as compared to $7.66 for the first quarter of 2008. During the three months ended March 31, 2009, the Company's average price realization for natural gas was $3.95 per Mcf, excluding realized gains and losses on commodity derivatives. The decrease in realized average natural gas prices partially offset by the increase in production contributed to a 38% decrease in revenues to $168.0 million as compared to $271.1 million in 2008.

Lease operating expense ("LOE") decreased to $10.2 million at March 31, 2009 compared to $10.7 million at March 31, 2008 due primarily to decreased costs related to water disposal on non-operated properties during the quarter ended March 31, 2009. On a unit of production basis, LOE costs decreased to $0.24 per Mcfe at March 31, 2009 compared to $0.32 per Mcfe at March 31, 2008 as a result of reduced water disposal costs on non-operated properties.

During the first quarter of 2009, production taxes were $17.4 million compared to $30.9 million during the first quarter of 2008, or $0.41 per Mcfe, compared to $0.91 per Mcfe. The decrease in per unit taxes is attributable to decreased sales revenues as a result of lower realized gas prices partially offset by increased production during the quarter ended March 31, 2009 as compared to the same period in 2008. Production taxes are calculated based on a percentage of revenue from production.

Gathering fees increased to $10.8 million at March 31, 2009 compared to $10.0 million at March 31, 2008 largely due to increased production volumes. On a per unit basis, gathering fees decreased to $0.26 per Mcfe for the three months ended March 31, 2009 as compared to $0.29 per Mcfe for the same period in 2008 as a result of increased production volumes.

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 $13.4 million for the quarter ended March 31, 2009 as compared to $9.7 million for the same period in 2008 in association with REX Pipeline demand charges. On a per unit basis, transportation demand charges increased to $0.32 per Mcfe for the three months ended March 31, 2009 as compared to $0.28 per Mcfe for the same period in 2008. Interim service at various delivery points on REX - West became available during the first quarter of 2008 while service on REX - West was available during the entire quarter ended March 31, 2009.

Depletion, depreciation and amortization ("DD&A") expenses increased to $60.7 million during the quarter ended March 31, 2009 from $42.3 million for the same period in 2008, attributable to increased production volumes and a higher depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.44 per Mcfe at March 31, 2009 from $1.24 at March 31, 2008.

The Company recorded a $1.0 billion non-cash write-down of the carrying value of the Company's proved oil and gas properties at March 31, 2009 as a result of ceiling test limitations. Under the full cost method of accounting, the ceiling test limits 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. The capitalized costs exceeded the ceiling limitation at March 31, 2009 and the Company recorded a write-down to the extent of the excess as a non-cash charge to earnings. The write-down reduced earnings in first quarter of 2009 and will result in lower DD&A expense in future periods.

General and administrative expenses remained relatively flat at $4.6 million ($0.11 per Mcfe) at March 31, 2009 compared to $4.3 million ($0.13 per Mcfe) for the same period in 2008.

Interest expense increased to $7.3 million during the quarter ended March 31, 2009 compared to $5.3 million during the same period in 2008 as a result of increased borrowings during the quarter ended March 31, 2009. At March 31, 2009, the Company had $721.0 million in borrowings outstanding.

Other expense increased to $2.6 million as of March 31, 2009 primarily as a result of rig termination payments during the quarter ended March 31, 2009.

During the quarter ended March 31, 2009, the Company recognized $20.4 million and $186.1 million related to realized gain on commodity derivatives and unrealized gain on commodity derivatives, respectively as compared to $27.7 million in unrealized loss on commodity derivatives during the quarter ended March 31, 2008. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under these derivative contracts while the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments.

The Company recognized a loss before income taxes of $789.5 million for the quarter ended March 31, 2009 compared with income of $130.4 million for the same period in 2008. The decrease in earnings is primarily a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation, decreased natural gas prices partially offset by increased production and gains on commodity derivatives during the quarter ended March 31, 2009 as compared to the same period in 2008.

The income tax benefit recognized for the quarter ended March 31, 2009 was $276.9 million compared with an income tax provision of $47.0 million for the three months ended March 31, 2008 due to a net loss during the quarter ended March 31, 2009 primarily as a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation.

For the quarter ended March 31, 2009, the Company recognized a net loss of $512.6 million or $3.39 per diluted share as compared with net income of $83.3 million or $0.53 per diluted share for the same period in 2008 primarily attributable to the non-cash write-down of oil and gas properties associated with the ceiling test limitation, decreased natural gas prices partially offset by increased production and gains on commodity derivatives during the quarter ended March 31, 2009 as compared to the same period in 2008.

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 three month period ended March 31, 2009, the Company relied on cash provided by operations along with borrowings under the senior credit facility and the issuance of the 2009 Senior Notes to finance its capital expenditures. The Company participated in the drilling of 111 wells in Wyoming and Pennsylvania. For the three month period ended March 31, 2009, net capital expenditures were $221.9 million. At March 31, 2009, the Company reported a cash position of $14.4 million compared to $46.3 million at March 31, 2008. Working capital at March 31, 2009 was $84.7 million compared to a deficit of $109.0 million at March 31, 2008. At March 31, 2009, we had $186.0 million in outstanding borrowings and $314.0 million of available borrowing capacity under our credit facility. In addition, the Company had $300.0 million and $235.0 million outstanding under its 2008 Senior Notes and 2009 Senior Notes, respectively, at March 31, 2009 (See Note 3) and other long-term obligations of $57.4 million at March 31, 2009 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 2009, which are currently projected to be $670.0 million. Of the $670.0 million budget, the Company plans to allocate approximately 90% to Wyoming and 10% 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.

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 March 31, 2009).

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 March 31, 2009, we were in compliance with all of our debt covenants under our credit facility.

Senior Notes, due 2016 and 2019: On March 5, 2009, our wholly-owned subsidiary, Ultra Resources, Inc., issued $235.0 million Senior Notes ("the 2009 Senior . . .