November 07, 2017 09:15 ET | Source: Ultra Petroleum Corp. Ultra Petroleum Corp.
HOUSTON, Nov. 07, 2017 (GLOBE NEWSWIRE) -- Ultra Petroleum Corp. (NASDAQ:UPL) announces financial and operating results for the third quarter of 2017.
Third Quarter 2017 Financial and Operating Highlights:
"The third quarter was a solid one for us as we transition from a more reactive, restructuring phase to one focused on thoughtful, strategic capital allocation that balances growth with free cash flow generation and resource expansion," said Michael D. Watford, Chairman, President and Chief Executive Officer.
Third Quarter Financial Results
During the third quarter of 2017, total revenues increased 9% to $217.6 million as compared to $199.3 million during the third quarter of 2016. The Company’s production of natural gas and oil was 71.1 billion cubic feet equivalent (Bcfe), an increase of 6% sequentially, with 66.8 billion cubic feet (Bcf) of natural gas and 705.1 thousand barrels (MBbls) of oil and condensate.
During the third quarter of 2017, Ultra Petroleum’s average realized natural gas price was $2.87 per thousand cubic feet (Mcf), which includes realized gains on commodity hedges. Excluding the realized gains from commodity derivatives, the Company’s average price for natural gas was $2.74 per Mcf, compared to $2.62 per Mcf for the third quarter of 2016. The Company’s average realized oil and condensate price was $45.86 per barrel (Bbl) for the quarter ended September 30, 2017 as compared to $41.55 per Bbl for the same period in 2016.
Ultra Petroleum’s reported net loss was $(327.7) million, or $(1.67) per diluted share. Ultra reported adjusted net income (2) of $78.8 million, or $0.40 per diluted share for the quarter ended September 30, 2017.
Year to Date 2017 Financial Results
During the nine months ended September 30, 2017, total revenues increased 29% to $651.2 million as compared to $505.2 million during the same period in 2016. During the first nine months of 2017, production of natural gas and oil was 202.2 Bcfe, which was comprised of 189.9 Bcf of natural gas and 2.0 million barrels of oil and condensate.
During the first nine months of 2017, Ultra Petroleum’s average realized natural gas price was $2.95 per Mcf, including realized gains on commodity hedges. Excluding the realized gains from commodity derivatives, the Company’s average price for natural gas was $2.91 per Mcf compared to $2.13 per Mcf for the same period in 2016. The Company’s average realized oil and condensate price was $46.21 per Bbl for the nine months ended September 30, 2017 as compared to $35.98 per Bbl for the same period in 2016.
Ultra Petroleum’s reported net income for the nine months ended September 30, 2017 was $81.6 million, or $0.53 per diluted share, with adjusted net income (2) of $249.6 million, or $1.63 per diluted share.
Hedging Activity
Ultra Petroleum enters into hedges for volumes equivalent to a portion of expected future production volumes in order to increase the predictability of its cash flows and to help maintain a strong, flexible financial position. At September 30, 2017, the Company has the following hedges in place:
| NYMEX | Q4 2017 | Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | |||||
| Natural Gas Swaps: | ||||||||||
| Volume (Bcf) | 16.9 | — | 10.2 | 10.4 | 3.5 | |||||
| $/Mcf | $ | 3.34 | $ | — | $ | 3.15 | $ | 3.15 | $ | 3.15 |
| Natural Gas Collars: | ||||||||||
| Volume (Bcf) | — | 3.4 | — | — | — | |||||
| Floor Price: $/Mcf | $ | — | $ | 3.45 | $ | — | $ | — | $ | — |
| Ceiling Price: $/Mcf | $ | — | $ | 3.76 | $ | — | $ | — | $ | — |
| * Based on a 1.065 BTU uplift | ||||||||||
Third Quarter 2017 Operational Highlights, Horizontal Well Success and New Investor Presentation
Ultra has updated its investor presentation. Please see www.ultrapetroleum.com under the Investors tab, “Events & Presentations” for the presentation entitled “Investor Update”.
Pinedale Horizontal Program Update
The Company recently drilled and completed a two-mile horizontal well on the east flank of Pinedale. This well targeted the Lower Lance A section and encountered significant gas shows throughout the entire 10,300’ lateral. Flowback was initiated on November 1 st and the well is currently flowing at 21 MMcfed (10% condensate) and is still increasing. The Company expects the clean-up period of the flow-back operation to continue for 2-3 weeks. The total well cost is estimated at $9 million, which is expected to decrease over time as more horizontals are drilled.
Currently, the Company is drilling another horizontal well on the east flank that is targeting a deeper interval in the Mesaverde formation. This well should be drilled and completed by year-end 2017. A third well, designed as a half-mile offset to the recent well in the Lower Lance A, is scheduled to spud by the end of December 2017.
During the third quarter, the Company and its partners brought online 63 gross (45.2 net) vertical wells in Pinedale with an average initial production (IP) rate for new operated vertical wells brought online of 6.8 million cubic feet equivalent (MMcfe) per day. The average condensate yield from these third quarter wells was 10.5 barrels per million cubic feet (MMcf). Contributing to this increase in production and activity was the Company’s ramp up to eight operated rigs in Pinedale by the end of August.
Year-to-date results for new operated Pinedale vertical wells are tabulated below:
“With the additional rigs added to the fleet in 2017, we drilled a number of wells on the eastern flank of the field due largely to constraints related to our bankruptcy process. While IP’s are lower in this part of the field, condensate yields are higher and provide a boost to returns. As vertical drilling moves more to the core of the field over the next two years, we expect IP’s to increase back towards our historical averages,” said Brad Johnson, Senior Vice President, Operations.
During the third quarter, the Company produced a total of 67.0 Bcfe in Wyoming, averaging 728 MMcfe per day comprised of 693 MMcf per day of natural gas and 5,851 barrels of condensate per day.
Since August 30, 2017, the Company’s volumes have been impacted by third-party gas gathering system outages. We continue to work with the gatherer to resolve the issue and anticipate resolution during the fourth quarter. In addition, the Company’s non-operated assets in the northern Pinedale field were impacted by drilling and completion schedule interruptions caused by operator ownership changes. In aggregate, the total impact to production related to these two events is estimated to be 2.0 billion cubic feet during 2017.
The Company averaged 8.4 days to drill an operated vertical well in the third quarter, as measured by spud to total depth (TD). This compares to 9.4 days to drill an operated vertical well in the second quarter. The decreased cycle time of one day reflects improved efficiencies now that the new rigs have been fully integrated into the fleet. Total days per vertical well, measured by rig-release to rig-release, averaged 10.6 days in the third quarter, which compares to 11.4 days in the second quarter of 2017.
During the third quarter of 2017, net production in Utah was 213.8 thousand barrels of oil equivalent, or 2,324 barrels of oil equivalent per day.
The Company produced 2.8 Bcf, averaging 31 MMcf per day during the third quarter of 2017.
Liquidity and Asset Sales
The Company increased its liquidity to approximately $400.0 million as of September 30, 2017 with the closing of a $175.0 million incremental senior secured term loan offering. The proceeds of the loan were used to refinance borrowings under the Senior Secured RBL Revolving Credit Facility.
The Company has interviewed investment banks to explore divesting non-core assets in the Uinta basin and in the Marcellus shale and is in the final stages of selecting investment banks.
Fourth Quarter and Year-to Date 2017 Guidance
Capital Investment: The Company is reaffirming its 2017 total capital budget at $540 million, which includes $15 million related to acquisitions during the second quarter.
Production: The Company expects that fourth quarter 2017 production will be approximately 75 Bcfe, which has been impacted by unplanned downtime caused by a third party provider and ownership transition in the Company’s non-operated Pinedale properties.
Price Realizations and Differentials: During the fourth quarter, the Company's realized natural gas price per Mcf is expected to average 3 to 5 percent below the NYMEX price due to regional differentials, before consideration of any hedging activity. Realized pricing for oil is expected to be approximately 4 to 5 percent less than the average NYMEX crude oil price in the fourth quarter.
Expenses: The following table presents the Company's expected per unit of production expenses for the fourth quarter of 2017 assuming a $2.90 per MMBtu Henry Hub natural gas price and a $54.00 per Bbl NYMEX crude oil price:
| Costs Per Mcfe | 4Q 2017 | |
| Lease operating expenses | $ | 0.30 – 0.33 |
| Facility lease expense | $ | 0.07 – 0.07 |
| Production taxes | $ | 0.32 – 0.34 |
| Gathering fees (net) | $ | 0.27 – 0.29 |
| Transportation charges | $ | 0.00 – 0.00 |
| Depletion and depreciation | $ | 0.56 – 0.60 |
| General and administrative-cash | $ | 0.02 – 0.04 |
| Interest expense | $ | 0.45 – 0.47 |
| Total operating costs per Mcfe | $ | 1.99 – 2.14 |
Income Tax: Ultra Petroleum recorded a $6.9 million tax receivable for the quarter ended September 30, 2017, which is related to U.S. cash tax refunds. The Company does not expect any tax expense or credits for the remainder of 2017.
Conference Call Webcast Scheduled for November 7, 2017
Ultra Petroleum’s third quarter 2017 results conference call will be available via live webcast at 11:00 a.m. Eastern Standard Time (10:00 a.m. Central Standard Time) Tuesday, November 7, 2017. To listen to this webcast, log on to www.ultrapetroleum.com and follow the link to the webcast. The webcast replay will be archived on Ultra Petroleum’s website.
Financial tables to follow.
| Ultra Petroleum Corp. | ||||||||||||||||
| Consolidated Statements of Operations (unaudited) | ||||||||||||||||
| All amounts expressed in US$000's, | ||||||||||||||||
| Except per unit data | ||||||||||||||||
| For the Nine Months Ended | For the Quarter Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| Volumes: | ||||||||||||||||
| Natural gas (Mcf) | 189,900,648 | 200,286,232 | 66,844,448 | 65,244,794 | ||||||||||||
| Oil and condensate (Bbls) | 2,043,191 | 2,205,145 | 705,057 | 680,064 | ||||||||||||
| Mcfe - Total | 202,159,794 | 213,517,102 | 71,074,790 | 69,325,178 | ||||||||||||
| Revenues: | ||||||||||||||||
| Natural gas sales | $ | 551,797 | $ | 425,878 | $ | 182,949 | $ | 170,996 | ||||||||
| Oil sales | 94,415 | 79,352 | 32,334 | 28,257 | ||||||||||||
| Other revenue | 5,035 | - | 2,348 | - | ||||||||||||
| Total operating revenues | 651,247 | 505,230 | 217,631 | 199,253 | ||||||||||||
| Expenses: | ||||||||||||||||
| Lease operating expenses | 69,365 | 67,164 | 23,140 | 19,934 | ||||||||||||
| Facility lease expense | 15,706 | 15,514 | 5,254 | 5,171 | ||||||||||||
| Production taxes | 66,369 | 49,394 | 22,482 | 20,688 | ||||||||||||
| Gathering fees | 63,753 | 65,112 | 22,182 | 21,159 | ||||||||||||
| Total lease operating costs | 215,193 | 197,184 | 73,058 | 66,952 | ||||||||||||
| Transportation charges | - | 23,750 | - | 49 | ||||||||||||
| Depletion and depreciation | 111,516 | 93,274 | 41,089 | 31,192 | ||||||||||||
| General and administrative | 126 | 3,229 | 329 | 331 | ||||||||||||
| Stock compensation | 34,182 | 3,967 | 7,918 | 1,264 | ||||||||||||
| Total operating expenses | 361,017 | 321,404 | 122,394 | 99,788 | ||||||||||||
| Other (expense) income, net | (28 | ) | (2,436 | ) | 92 | (514 | ) | |||||||||
| Restructuring expenses | - | (7,176 | ) | - | (28 | ) | ||||||||||
| Contract settlement expense | (52,707 | ) | - | - | - | |||||||||||
| Interest expense | (324,979 | ) | (66,565 | ) | (210,107 | ) | - | |||||||||
| Deferred gain on sale of liquids gathering system | 7,915 | 7,915 | 2,638 | 2,638 | ||||||||||||
| Realized gain on commodity derivatives | 8,016 | - | 8,884 | - | ||||||||||||
| Unrealized gain (loss) on commodity derivatives | 4,133 | - | (4,234 | ) | - | |||||||||||
| Total other (expense) income, net | (357,650 | ) | (68,262 | ) | (202,727 | ) | 2,096 | |||||||||
| Reorganization items, net | 142,147 | (25,292 | ) | (227,123 | ) | (3,109 | ) | |||||||||
| Income (loss) before income taxes | 74,727 | 90,272 | (334,613 | ) | 98,452 | |||||||||||
| Income tax (benefit) provision | (6,884 | ) | (305 | ) | (6,886 | ) | 45 | |||||||||
| Net income (loss) | $ | 81,611 | $ | 90,577 | $ | (327,727 | ) | $ | 98,407 | |||||||
| Adjusted Net Income Reconciliation: | ||||||||||||||||
| Net income (loss) | $ | 81,611 | $ | 90,577 | $ | (327,727 | ) | $ | 98,407 | |||||||
| Reorganization items, net | (142,147 | ) | 25,292 | 227,123 | 3,109 | |||||||||||
| Postpetition interest expense | 260,977 | - | 175,179 | - | ||||||||||||
| Contract settlement expense | 52,707 | - | - | - | ||||||||||||
| Restructuring expenses | - | 7,176 | - | 28 | ||||||||||||
| Unrealized (gain) loss on commodity derivatives | (4,133 | ) | - | 4,234 | - | |||||||||||
| Deferred taxes | - | 1 | - | - | ||||||||||||
| Other | 604 | 2,923 | 21 | 811 | ||||||||||||
| Adjusted net income (2) | $ | 249,619 | $ | 125,969 | $ | 78,830 | $ | 102,355 | ||||||||
| Operating cash flow (1) (7)(8) | $ | 386,942 | $ | 201,569 | $ | 125,199 | $ | 129,035 | ||||||||
| (see non-GAAP reconciliation) | ||||||||||||||||
| Adjusted EBITDA (5) | $ | 444,520 | $ | 281,554 | $ | 153,241 | $ | 132,218 | ||||||||
| (see non-GAAP reconciliation) | ||||||||||||||||
| Weighted average shares (000's) (9) | ||||||||||||||||
| Basic | 152,864 | 79,991 | 196,331 | 80,003 | ||||||||||||
| Diluted | 153,068 | 80,361 | 196,331 | 80,384 | ||||||||||||
| Earnings (loss) per share (9) | ||||||||||||||||
| Net income (loss) - basic | $ | 0.53 | $ | 1.13 | $ | (1.67 | ) | $ | 1.23 | |||||||
| Net income (loss)- diluted | $ | 0.53 | $ | 1.13 | $ | (1.67 | ) | $ | 1.22 | |||||||
| Adjusted earnings per share (2) (9) | ||||||||||||||||
| Adjusted net income - basic | $ | 1.63 | $ | 1.57 | $ | 0.40 | $ | 1.28 | ||||||||
| Adjusted net income - diluted | $ | 1.63 | $ | 1.57 | $ | 0.40 | $ | 1.27 | ||||||||
| Realized Prices | ||||||||||||||||
| Natural gas ($/Mcf), excluding realized gain on commodity derivatives | $ | 2.91 | $ | 2.13 | $ | 2.74 | $ | 2.62 | ||||||||
| Natural gas ($/Mcf), including realized gain on commodity derivatives | $ | 2.95 | $ | 2.13 | $ | 2.87 | $ | 2.62 | ||||||||
| Oil liquids ($/Bbl) | $ | 46.21 | $ | 35.98 | $ | 45.86 | $ | 41.55 | ||||||||
| Costs Per Mcfe | ||||||||||||||||
| Lease operating expenses | $ | 0.34 | $ | 0.31 | $ | 0.33 | $ | 0.29 | ||||||||
| Facility lease expense | $ | 0.08 | $ | 0.07 | $ | 0.07 | $ | 0.07 | ||||||||
| Production taxes | $ | 0.33 | $ | 0.23 | $ | 0.32 | $ | 0.30 | ||||||||
| Gathering fees (net) | $ | 0.29 | $ | 0.30 | $ | 0.28 | $ | 0.31 | ||||||||
| Transportation charges | $ | - | $ | 0.11 | $ | - | $ | - | ||||||||
| Depletion and depreciation | $ | 0.55 | $ | 0.44 | $ | 0.58 | $ | 0.45 | ||||||||
| General and administrative - total | $ | 0.17 | $ | 0.03 | $ | 0.12 | $ | 0.02 | ||||||||
| Interest expense (7) | $ | 0.32 | $ | 0.31 | $ | 0.49 | $ | - | ||||||||
| $ | 2.08 | $ | 1.80 | $ | 2.19 | $ | 1.44 | |||||||||
| Adjusted Margins | ||||||||||||||||
| Adjusted Net Income Margin (3) | 38 | % | 25 | % | 36 | % | 51 | % | ||||||||
| Adjusted Operating Cash Flow Margin (4)(7)(8) | 59 | % | 40 | % | 58 | % | 65 | % | ||||||||
| Adjusted EBITDA Margin (6) | 68 | % | 56 | % | 70 | % | 66 | % | ||||||||
| Ultra Petroleum Corp. Supplemental Balance Sheet Data All amounts expressed in US$000’s | ||||||||
| As of | ||||||||
| September 30, | December 31, | |||||||
| 2017 | 2016 | |||||||
| (Unaudited) | ||||||||
| Cash and cash equivalents | $ | 5,419 | $ | 401,478 | ||||
| Outstanding debt | ||||||||
| Term Loan, secured due 2024 | 975,000 | - | ||||||
| 6.875% Senior Notes, unsecured due 2022 | 700,000 | - | ||||||
| 7.125% Senior Notes, unsecured due 2025 | 500,000 | - | ||||||
| 6.125% Senior Notes due 2024 | - | 850,000 | ||||||
| 5.75% Senior Notes due 2018 | - | 450,000 | ||||||
| Senior Notes issued by Ultra Resources, Inc. | - | 1,460,000 | ||||||
| Credit Agreement | 20,000 | 999,000 | ||||||
| Total long-term debt | $ | 2,195,000 | $ | 3,759,000 | ||||
| Less: Deferred financing costs | (60,986 | ) | - | |||||
| Less: Liabilities subject to compromise | - | (3,759,000 | ) | |||||
| Total long-term debt not subject to compromise | $ | 2,134,014 | $ | - | ||||
Reconciliation of Operating Cash Flow and Net Cash Provided by Operating Activities (unaudited)
All amounts expressed in US$000's
The following table reconciles net cash provided by operating activities with operating cash flow as derived from the Company’s financial information.
| For the Nine Months Ended | For the Quarter Ended | ||||||||||
| September 30, | September 30, | ||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||
| Net cash provided by operating activities | $ | 164,518 | $ | 170,798 | $ | 38,135 | $ | 139,060 | |||
| Net changes in operating assets and liabilities and other non-cash or non-recurring items (7)(8) | 222,424 | 30,771 | 87,064 | (10,025 | ) | ||||||
| Operating Cash Flow (1) | $ | 386,942 | $ | 201,569 | $ | 125,199 | $ | 129,035 | |||
Reconciliation of Earnings before Interest, Taxes, Depletion and Amortization (unaudited)
All amounts expressed in US$000's
The following table reconciles net income (loss) as derived from the Company's financial information with earnings before interest, taxes, depletion, and amortization and certain other non-recurring or non-cash charges (Adjusted EBITDA) (5) :
| For the Nine Months Ended | For the Quarter Ended | ||||||||||
| September 30, | September 30, | ||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||
| Net income (loss) | $ | 81,611 | $ | 90,577 | $ | (327,727 | ) | $ | 98,407 | ||
| Interest expense | 324,979 | 66,565 | 210,107 | - | |||||||
| Depletion and depreciation | 111,516 | 93,274 | 41,089 | 31,192 | |||||||
| Reorganization items, net | (142,147 | ) | 25,292 | 227,123 | 3,109 | ||||||
| Contract settlement expense | 52,707 | - | - | - | |||||||
| Unrealized (gain)/loss on commodity derivatives | (4,133 | ) | - | 4,234 | - | ||||||
| Restructuring expenses | - | 7,176 | - | 28 | |||||||
| Deferred gain on sale of liquids gathering system | (7,915 | ) | (7,915 | ) | (2,638 | ) | (2,638 | ) | |||
| Stock compensation expense | 34,182 | 3,967 | 7,918 | 1,264 | |||||||
| Taxes | (6,884 | ) | (305 | ) | (6,886 | ) | 45 | ||||
| Other | 604 | 2,923 | 21 | 811 | |||||||
| Adjusted EBITDA (5) | $ | 444,520 | $ | 281,554 | $ | 153,241 | $ | 132,218 | |||
The Company reports its financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of the Company’s peers and of prior periods.
Management presents the following measures because (i) they are consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
(1) Operating Cash Flow is defined as Net cash provided by operating activities before changes in operating assets and liabilities and other non-cash items. Management believes that the non-GAAP measure of operating cash flow is useful as an indicator of an oil and gas exploration and production Company's ability to internally fund exploration and development activities and to service or incur additional debt. The Company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the Company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.
(2) Adjusted Net Income is defined as Net income adjusted to exclude certain charges or amounts in order to exclude the volatility associated with the effects of non-recurring charges, non-cash mark-to-market gains or losses on commodity derivatives, non-cash ceiling test impairments and other similar items such as post-petition interest which represents interest expense related to the prepetition debt agreements incurred as part of our emergence from chapter 11 proceedings.
(3) Adjusted Net Income Margin is defined as Adjusted Net Income divided by Total operating revenues plus Realized gain (loss) on commodity derivatives, if any.
(4) Adjusted Operating Cash Flow Margin is defined as Operating Cash Flow divided by Total operating revenues plus Realized gain (loss) on commodity derivatives, if any.
(5) Earnings before interest, taxes, depletion and amortization (Adjusted EBITDA) is defined as Net income (loss) adjusted to exclude interest, taxes, depletion and amortization and certain other non-recurring or non-cash charges. Management believes that the non-GAAP measure of Adjusted EBITDA is useful as an indicator of an oil and gas exploration and production Company's ability to internally fund exploration and development activities and to service or incur additional debt. Adjusted EBITDA should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.
(6) Adjusted EBITDA Margin is defined as Adjusted EBITDA divided by Total operating revenues plus Realized gain (loss) on commodity derivatives, if any.
(7) For the three and nine months ended September 30, 2017, excludes postpetition interest expense that represents interest for the period beginning April 29, 2016 through April 12, 2017.
(8) For the nine months and quarter ended September 30, 2017, reorganization items, net and contract settlement expense are considered non-recurring items and are excluded from operating cash flow.
(9) In conjunction with emergence from chapter 11, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562 on April 12, 2017. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred as of January 1, 2016.
(10) Cash operating margin is defined as Total operating revenues plus Realized gain (loss) on commodity derivatives per Mcfe, if any, less lease operating expense, operating lease expense, production taxes, gathering fees and transportation charges, per Mcfe.
About Ultra Petroleum
Ultra Petroleum Corp. is an independent energy Company engaged in domestic natural gas and oil exploration, development and production. The Company is listed on NASDAQ and trades under the ticker symbol “UPL”. Additional information on the Company is available at www.ultrapetroleum.com.
This news release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Any statement, including any opinions, forecasts, projections or other statements, other than statements of historical fact, are or may be forward-looking statements. Although the Company believes the expectations reflected in any forward-looking statements herein are reasonable, we can give no assurance that such expectations will prove to have been correct and actual results may differ materially from those projected or reflected in such statements. Certain risks and uncertainties inherent in our business as well as risks and uncertainties related to our operational and financial results are set forth in our filings with the SEC, particularly in the section entitled “Risk Factors” included in our most recent Annual Report on Form 10-K for the most recent fiscal year, our most recent Quarterly Reports on Form 10-Q, and from time to time in other filings made by the Company with the SEC. Some of these risks and uncertainties include, but are not limited to, increased competition, the timing and extent of changes in prices for oil and gas, particularly in the areas where we own properties, conduct operations, and market our production, as well as the timing and extent of our success in discovering, developing, producing and estimating oil and gas reserves, weather and government regulation, and the availability of oil field services, personnel and equipment. Our SEC filings are available by written request to Ultra Petroleum Corp. at 400 North Sam Houston Parkway East, Suite 1200, Houston, Texas 77060 (Attention: Investor Relations) or on our website (www.ultrapetroleum.com) or from the SEC on their website at www.sec.gov or by telephone request at 1-800-SEC-0330.
For further information contact:
Sandi Kraemer
Director, Investor Relations
Phone: 281-582-6613
Email: skraemer@ultrapetroleum.com