ENGLEWOOD, Colo., Nov. 08, 2018 (GLOBE NEWSWIRE) — Ultra Petroleum Corp. (NASDAQ: UPL) (“Ultra Petroleum” or the “Company”) announces financial and operating results for the quarter ended September 30, 2018.
Financial and Operating Highlights:
- Third quarter 2018 production averaged 734 MMcfe/d, above mid-point of guidance,
- Brought 19 vertical wells online with average 24-hour IP rate of 7.4 MMcfe/d,
- Reduced vertical well costs to $3.3 million, a 10% reduction from second quarter 2018, with continued reductions expected,
- Closed the previously announced sale of its Utah assets for $75 million with proceeds used to fully pay down the revolver balance at September 30, 2018,
- Liquidity as of September 30, 2018 of $338 million, including cash and availability under the revolver,
- Names two new executives, Chief Financial Officer and General Counsel,
- Completed relocation of the Company’s headquarters from Houston, Texas to Englewood, Colorado, and
- Additional financial and operating highlights can be found in the new investor presentation posted at www.ultrapetroleum.com.
Third Quarter 2018 Financial Results
During the third quarter of 2018, total revenues were $203.8 million as compared to $217.6 million during the third quarter of 2017. The Company’s production of natural gas and oil was 67.5 billion cubic feet equivalent (Bcfe), a decrease of 5% over the third quarter of 2017, with 63.8 billion cubic feet (Bcf) of natural gas and 624.2 thousand barrels (MBbls) of oil and condensate.
During the third quarter of 2018, Ultra Petroleum’s average realized natural gas price was $2.38 per thousand cubic feet (Mcf), which includes realized gains and losses on commodity hedges and compares to $2.87 for the same period in 2017. Excluding the realized gains and losses from commodity derivatives, the Company’s average price for natural gas was $2.46 per Mcf, compared to $2.74 per Mcf for the third quarter of 2017. The Company’s average realized oil and condensate price was $58.02 per barrel (Bbl), which includes realized losses on commodity hedges, for the quarter ended September 30, 2018. Excluding the realized losses from oil commodity derivatives, the Company’s average price for oil was $66.54 per Bbl as compared to $45.86 per Bbl for the same period in 2017.
Net income was $18.6 million, or $0.09 per diluted share. Ultra Petroleum reported adjusted net income(2) of $33.0 million, or $0.17 per diluted share for the quarter ended September 30, 2018.
Year-to-Date Financial Results
During the nine months ended September 30, 2018, total revenues were $619.3 million as compared to $651.2 million during the same period in 2017. During the first nine months of 2018, the Company’s production of natural gas and oil was 210.7 Bcfe, an increase of 4% over 2017, with 198.9 Bcf of natural gas and 2.0 million barrels (MMBbls) of oil and condensate.
During the first nine months of 2018, Ultra Petroleum’s average realized natural gas price was $2.45 per Mcf, which includes realized gains and losses on commodity hedges and compares to $2.95 per Mcf for the same period in 2017. Excluding realized gains and losses from commodity derivatives, the Company’s average price for natural gas was $2.41 per Mcf, compared to $2.91 per Mcf for the nine months ended September 30, 2017. The Company’s average realized oil and condensate price was $58.89 per Bbl, which includes realized losses on commodity hedges, for the nine months ended September 30, 2018. Excluding the realized losses from oil commodity derivatives, the Company’s average price for oil was $63.98 per Bbl as compared to $46.21 per Bbl for the same period in 2017.
Net income was $45.5 million, or $0.23 per diluted share. Ultra Petroleum reported adjusted net income(2) of $122.3 million, or $0.62 per diluted share for the nine months ended September 30, 2018.
Pinedale Vertical Program
During the third quarter, the Company and its partners brought online 24 gross (17.7 net) vertical wells in Pinedale. The average 24-hour initial production (IP) rate for new operated vertical wells brought online in the third quarter of 2018 was 7.4 million cubic feet equivalent (MMcfe) per day. Operated vertical well costs for the quarter was $3.3 million, a 10% reduction compared to second quarter 2018.
“Our vertical well costs are trending down toward historical averages as we have returned to pad drilling and simultaneous operations on pads dedicated to vertical development,” said Interim CEO Brad Johnson. “We are very focused on bringing down well costs and expect significant further improvement in the fourth quarter and into 2019.”
Pinedale Horizontal Program
During the third quarter, the Company completed three horizontal gross (2.2 net) wells targeting the Lower Lance A1 zone. A total of nine wells are now producing from the Lower Lance A1 zone with an average 24-hour IP rate of 20.8 million MMcfe/d.
The table below provides average results for each of the Lower Lance zones that the Company has drilled as well as details on the horizontal wells brought online:
| Well | Zone | IP Date | Lateral Length |
Net / Gross % |
Stage Count |
IP 24hr Mcfe/d |
IP 30d Mcfe/d |
IP Yield Bbls/MMcf |
| WB 9-23 A-1H | Lower Lance A1 | Nov-17 | 10,364 | 82% | 49 | 50,768 | 35,915 | 15.2 |
| WB 9-23 A-2H | Lower Lance A1 | Feb-18 | 10,978 | 78% | 49 | 54,459 | 36,816 | 17.7 |
| WB 8-25 A-1H | Lower Lance A1 | Apr-18 | 9,923 | 54% | 35 | 28,508 | 18,258 | 17.0 |
| WB 8-14 A-1H | Lower Lance A1 | Apr-18 | 7,159 | 80% | 35 | 16,165 | 9,610 | 25.4 |
| WB 7-23 4H | Lower Lance A1 | May-18 | 8,095 | 71% | 41 | 7,179 | 4,966 | 7.0 |
| WB 7-23 2H | Lower Lance A1 | Jun-18 | 6,525 | 53% | 24 | 6,873 | 4,176 | 14.2 |
| WB 8-25 W-4H | Lower Lance A1 | Jul-18 | 6,917 | 65% | 23 | 9,405 | 6,082 | 9.0 |
| WB 15-11 A-1H | Lower Lance A1 | Aug-18 | 6,377 | 86% | 37 | 11,486 | 5,987 | 20.0 |
| WB 8-25 SE-1H | Lower Lance A1 | Aug-18 | 5,431 | 49% | 22 | 2,462 | 1,636 | 10.8 |
| Lower Lance A1 Average | 7,974 | 69% | 39 | 20,812 | 13,625 | 15.1 | ||
| WB 9-23 A-3H | Lower Lance A2 | Apr-18 | 10,864 | 47% | 33 | 11,711 | 7,294 | 13.5 |
| WB 8-25 A-2H | Lower Lance A2 | Apr-18 | 9,916 | 38% | 36 | 8,427 | 5,420 | 14.9 |
| WB 7-23 3H | Lower Lance A2 | May-18 | 8,356 | 40% | 33 | 4,480 | 2,659 | 7.0 |
| WB 9-23 5H | Lower Lance A2 | May-18 | 8,657 | 65% | 34 | 7,554 | 5,540 | 13.1 |
| Lower Lance A2 Average | 9,448 | 48% | 34 | 8,043 | 5,228 | 12.1 | ||
| WB 8-14 3H | Lower Lance C1 | May-18 | 7,510 | 81% | 35 | 20,021 | 11,465 | 26.0 |
| WB 9-23 11H | Lower Lance C1 | Jun-18 | 10,821 | 45% | 25 | 4,107 | 2,718 | 18.5 |
| Lower Lance C1 Average | 9,166 | 63% | 29 | 12,064 | 7,092 | 22.3 | ||
| WB 8-14 4H | Lower Lance E1 | Jun-18 | 6,863 | 40% | 16 | 11,318 | 6,332 | 33.0 |
Mr. Johnson said, “We have expanded our technical efforts to analyze the significant amount of data we have gathered from the horizontal wells drilled this year. We will use this data to refine and optimize our horizontal program prior to drilling our next set of horizontal wells. While our near-term drilling efforts will be focused on our vertical program, we remain confident in our ability to unlock material incremental value from Pinedale through horizontal development.”
Hedging Activity
The table below provides a summary of the hedges in place as of November 5, 2018:
| NYMEX | Q4 2018 | Q1 2019 | Q2 2019 | Q3 2019 | Q4 2019 | Q1 2020 | ||||||||||||||||||||||||||||||||||
| Natural Gas Swaps: | ||||||||||||||||||||||||||||||||||||||||
| Volume (MMBtu/d) | 657,283 | 660,000 | 400,000 | 380,000 | 360,000 | 250,000 | ||||||||||||||||||||||||||||||||||
| $/MMBtu | $ | 2.88 | $ | 2.92 | $ | 2.75 | $ | 2.76 | $ | 2.77 | $ | 2.76 | ||||||||||||||||||||||||||||
| Natural Gas Collars: | ||||||||||||||||||||||||||||||||||||||||
| Volume (MMBtu/d) | 100,000 | |||||||||||||||||||||||||||||||||||||||
| Floor ($/MMBtu) | $ | 2.75 | ||||||||||||||||||||||||||||||||||||||
| Ceiling ($/MMBbtu) | $ | 3.18 | ||||||||||||||||||||||||||||||||||||||
| Oil Swaps: | ||||||||||||||||||||||||||||||||||||||||
| Volume (Bbl/d) | 6,500 | 6,000 | 6,000 | 4,000 | 3,000 | 1,000 | ||||||||||||||||||||||||||||||||||
| $/Bbl | $ | 60.45 | $ | 58.46 | $ | 59.16 | $ | 58.59 | $ | 59.23 | $ | 60.05 | ||||||||||||||||||||||||||||
| Basis Swap Contracts: | ||||||||||||||||||||||||||||||||||||||||
| NW Rockies basis swap volume (MMBtu/d)(a) financial | 559,674 | 572,500 | 120,000 | 120,000 | 120,000 | — | ||||||||||||||||||||||||||||||||||
| NW Rockies basis swap volume (MMBtu/d)(a) physical | 57,283 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Price differential ($/MMBtu) | $ | (0.66 | ) | $ | (0.66 | ) | $ | (0.77 | ) | $ | (0.77 | ) | $ | (0.77 | ) | $ | — | |||||||||||||||||||||||
(a) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period.
2018 Guidance
The Company is adjusting its capital plan for the remainder of 2018. The Company is maintaining a three-rig program in the fourth quarter with all rigs currently focused on vertical development while we continue to refine and optimize the horizontal program.
Production: The Company is narrowing annual production guidance to a range of 274 – 278 Bcfe. In the fourth quarter, the average daily production rate is expected to range between 690-730 MMcfe/d.
Capital Investment: The Company is refining its 2018 total capital budget to a range of $400-415 million.
Expenses: The following table presents the Company’s expected per unit of production expenses for the fourth quarter of 2018. Production tax guidance assumes a $3.15 per MMBtu Henry Hub natural gas price and a $63.50 per Bbl NYMEX crude oil price:
| Costs Per Mcfe | 4Q 2018 | ||
| Lease operating expenses | $ | 0.30 – 0.33 | |
| Facility lease expense | $ | 0.09 – 0.11 | |
| Production taxes | $ | 0.37 – 0.39 | |
| Gathering fees, net | $ | 0.24 – 0.26 | |
| Transportation charges | $ | 0.00 – 0.00 | |
| Depletion and depreciation | $ | 0.72 – 0.76 | |
| General and administrative-cash | $ | 0.02 – 0.04 | |
| Interest expense | $ | 0.57 – 0.59 | |
| Total costs per Mcfe | $ | 2.31 – 2.48 |
Income Tax: The Company does not expect any cash tax expense during the fourth quarter.
Ultra Petroleum Announces Appointment of Chief Financial Officer and General Counsel
Ultra Petroleum is announcing the appointment of Mr. David Honeyfield as Chief Financial Officer of the Company, and Mr. Andrew Kidd as General Counsel of the Company.
Mr. David Honeyfield has over 25 years of experience in the energy and natural resources fields with a strong background in accounting and the corporate management of public oil and gas companies. Most recently, Mr. Honeyfield served as Senior Vice President and Chief Financial Officer of PDC Energy, Inc. and Chief Financial Officer of Jonah Energy LLC. He has also served in various leadership roles including President and Chief Financial Officer of Intrepid Potash, Inc., Senior Vice President and Chief Financial Officer of SM Energy, and Controller and Chief Accounting Officer of Cimarex Energy Co. Additionally, Mr. Honeyfield was a Senior Audit Manager with Arthur Andersen LLP in Denver, where he focused on clients in the oil and gas exploration and production, manufacturing and mining sectors. Mr. Honeyfield holds a Bachelor of Arts degree in economics from the University of Colorado and is a Certified Public Accountant.
Mr. Andrew Kidd has over 29 years of experience advising clients in the energy industry with a strong background in managing legal risk related to oil and gas operations, drilling and development, as well as experience in corporate and project finance, and mergers and acquisitions. Mr. Kidd serves on the boards of directors of Highpoint Resources Corporation and Genon Americas Generation, Inc., and has been providing legal consulting services to institutional investors in the energy industry. Prior to those roles, Mr. Kidd held positions including General Counsel, President, and Chief Executive Officer at Samson Resources Corporation, and General Counsel of Quantum Utility Generation, LLC, Anthem Energy, LLC, and Constellation Energy Resources. Mr. Kidd received his Bachelor of Arts degree from Dartmouth College and his Juris Doctorate degree, with honors, from the University of Maryland Francis King Carey School of Law, where he was an editor of the University of Maryland Law Review.
“We are excited to have David and Andrew join the Ultra Petroleum executive team,” said Mr. Johnson. “Both have extensive backgrounds in the oil and gas industry and I am confident that their expertise and leadership will immediately contribute to the future growth and success of Ultra.”
Mr. Honeyfield and Mr. Kidd succeed Garland Shaw and Garrett Smith, respectively, who both did not relocate from Houston following the move of the Company’s headquarters to Englewood, Colorado.
“I want to thank Garland and Garrett for their years of service to this company,” said Mr. Johnson. “We are grateful to them for all of the hard work and dedication to Ultra and I wish to each of them all the best going forward.”
Conference Call Webcast Scheduled for November 8, 2018
The Company will host a conference call Thursday, November 8, 2018, at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) to discuss the Company’s third quarter 2018 results.
Investors and analysts are invited to participate in the call by dialing 1-877-371-5742, or 1-629-228-0726 for international calls, using Conference ID: 9583129. Interested parties may also listen over the internet at www.ultrapetroleum.com. A replay of the call will be available on the Company’s website.
Financial tables to follow.
Ultra Petroleum Corp.
Consolidated Statements of Operations (unaudited)
All amounts expressed in US$000’s, except per share data
| For the Nine Months Ended | For the Quarter Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Volumes: | ||||||||||||||||
| Natural gas (MMcf) | 198,917 | 189,902 | 63,790 | 66,845 | ||||||||||||
| Oil and condensate (MBbls) | 1,969 | 2,043 | 624 | 705 | ||||||||||||
| MMcfe – Total | 210,731 | 202,159 | 67,534 | 71,074 | ||||||||||||
| Revenues: | ||||||||||||||||
| Natural gas sales | $ | 479,704 | $ | 551,797 | $ | 156,986 | $ | 182,949 | ||||||||
| Oil sales | 125,974 | 94,415 | 41,523 | 32,334 | ||||||||||||
| Other revenue | 13,611 | 5,035 | 5,267 | 2,348 | ||||||||||||
| Total operating revenues | 619,289 | 651,247 | 203,776 | 217,631 | ||||||||||||
| Expenses: | ||||||||||||||||
| Lease operating expenses | 71,226 | 69,365 | 25,817 | 23,140 | ||||||||||||
| Facility lease expense | 19,557 | 15,706 | 6,875 | 5,254 | ||||||||||||
| Production taxes | 62,623 | 66,369 | 20,470 | 22,482 | ||||||||||||
| Gathering fees | 69,046 | 63,753 | 21,810 | 22,182 | ||||||||||||
| Total lease operating costs | 222,452 | 215,193 | 74,972 | 73,058 | ||||||||||||
| Depletion and depreciation | 151,954 | 111,516 | 49,672 | 41,089 | ||||||||||||
| General and administrative | 16,233 | 34,308 | 1,482 | 8,247 | ||||||||||||
| Total operating expenses | 390,639 | 361,017 | 126,126 | 122,394 | ||||||||||||
| Other (expense) income, net | (404 | ) | (28 | ) | 1,137 | 92 | ||||||||||
| Contract settlement expense | (2,676 | ) | (52,707 | ) | (2,676 | ) | — | |||||||||
| Interest expense | (111,934 | ) | (324,979 | ) | (38,382 | ) | (210,107 | ) | ||||||||
| Deferred gain on sale of liquids gathering system | 7,915 | 7,915 | 2,638 | 2,638 | ||||||||||||
| Realized gain (loss) on commodity derivatives | (3,050 | ) | 8,016 | (10,786 | ) | 8,884 | ||||||||||
| Unrealized gain (loss) on commodity derivatives | (72,557 | ) | 4,133 | (11,018 | ) | (4,234 | ) | |||||||||
| Total other (expense) income, net | (182,706 | ) | (357,650 | ) | (59,087 | ) | (202,727 | ) | ||||||||
| Reorganization items, net | — | 142,147 | — | (227,123 | ) | |||||||||||
| Income (loss) before income taxes | 45,944 | 74,727 | 18,563 | (334,613 | ) | |||||||||||
| Income tax provision | 442 | (6,884 | ) | – | (6,886 | ) | ||||||||||
| Net income (loss) | $ | 45,502 | $ | 81,611 | $ | 18,563 | $ | (327,727 | ) | |||||||
| Adjusted Net Income Reconciliation: | ||||||||||||||||
| Net income (loss) | $ | 45,502 | $ | 81,611 | $ | 18,563 | $ | (327,727 | ) | |||||||
| Reorganization items, net | — | (142,147 | ) | — | 227,123 | |||||||||||
| Postpetition interest expense | — | 260,977 | — | 175,179 | ||||||||||||
| Contract settlement expense | 2,676 | 52,707 | 2,676 | — | ||||||||||||
| Unrealized (gain) loss on commodity derivatives | 72,557 | (4,133 | ) | 11,018 | 4,234 | |||||||||||
| Other | 1,599 | 604 | 746 | 21 | ||||||||||||
| Adjusted net income (2) | $ | 122,334 | $ | 249,619 | $ | 33,003 | $ | 78,830 | ||||||||
| Operating cash flow (1) (7)(8) | $ | 277,920 | $ | 386,942 | $ | 81,461 | $ | 125,199 | ||||||||
| (see non-GAAP reconciliation) | ||||||||||||||||
| Adjusted EBITDA (5) | $ | 390,296 | $ | 444,520 | $ | 119,843 | $ | 153,241 | ||||||||
| (see non-GAAP reconciliation) | ||||||||||||||||
| Weighted average shares (000’s) (9) | ||||||||||||||||
| Basic | 196,888 | 152,864 | 197,054 | 196,331 | ||||||||||||
| Diluted | 197,288 | 153,068 | 197,055 | 196,331 | ||||||||||||
| Earnings (loss) per share | ||||||||||||||||
| Net income (loss) – basic | $ | 0.23 | $ | 0.53 | $ | 0.09 | $ | (1.67 | ) | |||||||
| Net income (loss)- diluted | $ | 0.23 | $ | 0.53 | $ | 0.09 | $ | (1.67 | ) | |||||||
| Adjusted earnings per share (2) (9) | ||||||||||||||||
| Adjusted net income – basic | $ | 0.62 | $ | 1.63 | $ | 0.17 | $ | 0.40 | ||||||||
| Adjusted net income – diluted | $ | 0.62 | $ | 1.63 | $ | 0.17 | $ | 0.40 | ||||||||
| Realized Prices | ||||||||||||||||
| Natural gas ($/Mcf), excluding realized gain on commodity derivatives |
$ | 2.41 | $ | 2.91 | $ | 2.46 | $ | 2.74 | ||||||||
| Natural gas ($/Mcf), including realized gain on commodity derivatives |
$ | 2.45 | $ | 2.95 | $ | 2.38 | $ | 2.87 | ||||||||
| Oil liquids ($/Bbl), excluding realized gain on commodity derivatives |
$ | 63.98 | $ | 46.21 | $ | 66.54 | $ | 45.86 | ||||||||
| Oil liquids ($/Bbl), including realized gain on commodity derivatives |
$ | 58.89 | $ | 46.21 | $ | 58.02 | $ | 45.86 | ||||||||
| Costs Per Mcfe | ||||||||||||||||
| Lease operating expenses | $ | 0.34 | $ | 0.34 | $ | 0.38 | $ | 0.33 | ||||||||
| Facility lease expense | $ | 0.09 | $ | 0.08 | $ | 0.10 | $ | 0.07 | ||||||||
| Production taxes | $ | 0.30 | $ | 0.33 | $ | 0.30 | $ | 0.32 | ||||||||
| Gathering fees (net) | $ | 0.26 | $ | 0.29 | $ | 0.24 | $ | 0.28 | ||||||||
| Depletion and depreciation | $ | 0.72 | $ | 0.55 | $ | 0.74 | $ | 0.58 | ||||||||
| General and administrative – total | $ | 0.08 | $ | 0.17 | $ | 0.02 | $ | 0.12 | ||||||||
| Interest expense (7) | $ | 0.53 | $ | 0.32 | $ | 0.57 | $ | 0.49 | ||||||||
| $ | 2.32 | $ | 2.08 | $ | 2.35 | $ | 2.19 | |||||||||
| Adjusted Margins | ||||||||||||||||
| Adjusted Net Income Margin (3) | 20 | % | 38 | % | 17 | % | 36 | % | ||||||||
| Adjusted Operating Cash Flow Margin (4)(7)(8) | 45 | % | 59 | % | 42 | % | 58 | % | ||||||||
| Adjusted EBITDA Margin (6) | 63 | % | 68 | % | 62 | % | 70 | % | ||||||||
Ultra Petroleum Corp.
Supplemental Balance Sheet Data
All amounts expressed in US$000’s
| As of | ||||||||
| September 30, | December 31, | |||||||
| 2018 | 2017 | |||||||
| (Unaudited) | ||||||||
| Cash and cash equivalents | $ | 13,141 | $ | 16,631 | ||||
| Outstanding debt | ||||||||
| Term Loan, secured due 2024 | 975,000 | 975,000 | ||||||
| 6.875% Senior Notes, unsecured due 2022 | 700,000 | 700,000 | ||||||
| 7.125% Senior Notes, unsecured due 2025 | 500,000 | 500,000 | ||||||
| Credit Agreement | — | — | ||||||
| Outstanding debt | $ | 2,175,000 | $ | 2,175,000 | ||||
| Less: Deferred financing costs | (51,796 | ) | (58,789 | ) | ||||
| Total outstanding debt, net | $ | 2,123,204 | $ | 2,116,211 | ||||
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, | |||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Net cash provided by operating activities | $ | 314,683 | $ | 148,784 | $ | 93,245 | $ | 12,322 | ||||||||
| Net changes in operating assets and liabilities and other non-cash or non-recurring items (7)(8) |
(36,763 | ) | 238,158 | (11,784 | ) | 112,877 | ||||||||||
| Operating Cash Flow (1) | $ | 277,920 | $ | 386,942 | $ | 81,461 | $ | 125,199 | ||||||||
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, | |||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Net income (loss) | $ | 45,502 | $ | 81,611 | $ | 18,563 | $ | (327,727 | ) | |||||||
| Interest expense | 111,934 | 324,979 | 38,382 | 210,107 | ||||||||||||
| Depletion and depreciation | 151,954 | 111,516 | 49,672 | 41,089 | ||||||||||||
| Reorganization items, net | — | (142,147 | ) | — | 227,123 | |||||||||||
| Contract settlement expense | 2,676 | 52,707 | 2,676 | — | ||||||||||||
| Unrealized (gain) loss on commodity derivatives | 72,557 | (4,133 | ) | 11,018 | 4,234 | |||||||||||
| Deferred gain on sale of liquids gathering system | (7,915 | ) | (7,915 | ) | (2,638 | ) | (2,638 | ) | ||||||||
| Stock compensation expense | 11,547 | 34,182 | 1,424 | 7,918 | ||||||||||||
| Taxes | 442 | (6,884 | ) | 0 | (6,886 | ) | ||||||||||
| Houston office relocation | 1,253 | — | 689 | — | ||||||||||||
| Other | 346 | 604 | 57 | 21 | ||||||||||||
| Adjusted EBITDA (5) | $ | 390,296 | $ | 444,520 | $ | 119,843 | $ | 153,241 | ||||||||
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 postpetition 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 quarter 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 quarter and nine months ended September 30, 2018 and 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 on April 12, 2017, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. 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, 2017.
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. In addition, our filings with the Securities and Exchange Commission (“SEC”) are available by written request to Ultra Petroleum Corp. at 116 Inverness Drive East, Suite 400, Englewood, CO 80112 (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.
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. This news release also includes forward-looking statements about the Company’s borrowing base, which is based in part upon estimates of the Company’s proved reserves. There are numerous uncertainties inherent in estimating proved reserves, including projecting future rates of production and timing of development. In addition, 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, our ability to successfully monetize the properties we are marketing, weather and government regulation, and the availability of oil field services, personnel and equipment.
For further information contact:
Investor Relations
303-708-9740, ext. 9898
Email: [email protected]
