Ultra Petroleum Announces Fourth Quarter and Year-To-Date 2017 Results, Successful Horizontal Well and Reports Year-End 2017 Reserves

HOUSTON, Feb. 28, 2018 (GLOBE NEWSWIRE) -- Ultra Petroleum Corp. (NASDAQ:UPL) announces financial and operating results for the quarter and year ended December 31, 2017.

Financial and Operating Highlights:

  • Fourth quarter production of 74.5 Bcfe increased 5% compared to third quarter 2017, meeting mid-point of guidance adjusting for Pennsylvania asset sale,
  • Drilled second successful horizontal well in the Lower Lance A: Flowing at 45 MMcfe/d (800 Bopd, 11% condensate) and increasing,
  • Drilled first successful horizontal well in the Mesaverde: 24-hr IP of 17 MMcfe/d,
  • Vertical IP’s increasing: January 2018 average IP = 8.1 MMcfe/d,
  • Increased hedges for 2018 forecasted volumes from 10% in third quarter 2017 to 65% currently; includes hedges for natural gas, oil and basis differentials,
  • Divested non-core assets in Pennsylvania for $115 million,
  • Reducing operated rig fleet from 7 rigs to 4; remaining rigs are equipped for horizontal development, and
  • Additional financial and operating highlights can be found in the new investor presentation posted at www.ultrapetroleum.com.

Fourth Quarter Financial Results

During the fourth quarter of 2017, total revenues increased 11% to $240.6 million as compared to $215.9 million during the fourth quarter of 2016. The Company’s production of natural gas and oil was 74.5 billion cubic feet equivalent (Bcfe), an increase of 5% sequentially, with 70.1 billion cubic feet (Bcf) of natural gas and 732.6 thousand barrels (MBbls) of oil and condensate.

During the fourth quarter of 2017, Ultra Petroleum’s average realized natural gas price was $2.86 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 $2.81 per Mcf, compared to $2.87 per Mcf for the fourth quarter of 2016. The Company’s average realized oil and condensate price was $53.17 per barrel (Bbl) for the quarter ended December 31, 2017 as compared to $45.27 per Bbl for the same period in 2016.

Ultra Petroleum’s reported net income was $95.5 million, or $0.49 per diluted share. Ultra reported adjusted net income(2) of $83.9 million, or $0.43 per diluted share for the quarter ended December 31, 2017.

Year to Date 2017 Financial Results

During the year ended December 31, 2017, total revenues increased 24% to $891.9 million as compared to $721.1 million during the same period in 2016. During the year ended December 31, 2017, production of natural gas and oil was 276.7 Bcfe, which was comprised of 260.0 Bcf of natural gas and 2.8 million barrels of oil and condensate.

During the year ended December 31, 2017, Ultra Petroleum’s average realized natural gas price was $2.92 per Mcf, including realized gains on commodity hedges. Excluding the realized gains from commodity derivatives, the Company’s average price for natural gas was $2.88 per Mcf compared to $2.31 per Mcf for the same period in 2016. The Company’s average realized oil and condensate price was $48.05 per Bbl for the year ended December 31, 2017 as compared to $38.24 per Bbl for the same period in 2016.

Ultra Petroleum’s reported net income for the year ended December 31, 2017 was $177.1 million, or $1.08 per diluted share, with adjusted net income(2) of $333.1 million, or $2.03 per diluted share.

Pinedale Horizontal Program

Earlier this month, the Warbonnet (WB) 9-23-A-2H well began its flowback and is currently producing at 45 MMcfe/d (800 Bopd, 11% condensate) and increasing. As the second horizontal well to target the Lower Lance A, this well was drilled to 22,690’ measured depth and a lateral length of 11,000’. The well was completed with 49 frac stages, 12.4 million pounds of sand and 281 thousand gallons of water. The estimated total cost of this well is $9 million. This well was drilled 7.5 days faster than the WB 9-23-A-1H and for $1 million less in total costs.

In November of last year, the Company reported a 24-hour IP of 51 MMcfed for its WB 9-23 A-1H well, a 2-mile lateral in the Lower Lance A interval. This well has since produced approximately 3.7 Bcfe in 120 days. Last month, the Company reported the WB 9-23 M-1H as a successful well in the Mesaverde interval, drilled from the same pad but with a landing zone that is 2,500’ lower than the Lower Lance A. This well posted a 24-hour IP of 17 MMcfe/d.

“Ultra has successfully drilled 4 horizontal wells in three different target intervals, with each well extending the commercial boundary of Pinedale. With these results, we are now ramping up our horizontal program in 2018 to include 15-20 horizontal wells,” said Brad Johnson, Interim Chief Executive Officer.

Pinedale Vertical Program

During the fourth quarter, the Company and its partners brought online 68 gross (57.0 net) vertical wells in Pinedale. During 2017, a total of 212 gross (171.5 net) vertical wells were brought online. The average initial production (IP) rate for new operated vertical wells brought online in 2017 was 6.7 million cubic feet equivalent (MMcfe) per day. In January 2018, 21 vertical wells were brought online with an average IP of 8.1 MMcfe/d.

“We have been shifting our vertical drilling program back to the core of Pinedale and average IPs are reverting back to historical averages,” said Brad Johnson, Interim Chief Executive Officer. “The 2018 vertical program should deliver stronger economic results and will be an important free cash flow component of our capital program in 2018 as we accelerate our transition to higher-return horizontals.”

Hedging Activity

Ultra Petroleum has increased its hedging position significantly since its last update provided on January 30, 2018. Currently, the Company’s forecasted volumes for 2018 are hedged at approximately 65% compared to 40% at year-end and 10% at the end of the third quarter 2017. The purpose of these hedges is provide a more certain and visible cash flow stream. The table below provides a summary of the hedges in place as of February 28, 2018:

NYMEX Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019
Natural Gas Swaps:
Volume (MMBtu/d) 770,000 770,000 524,674 250,000
$/MMBtu $ $2.88 $2.88 $2.88 $2.93
Oil Swaps:
Volume (Bbl/d) 2,000 4,000 4,000 4,000 1,000
$/Bbl $60.59 $59.80 $59.80 $59.80 $58.30
Natural Gas Collars:
Volume (MMBtu/d) 40,000
Floor Price: $/MMBtu $3.23 $ $ $ $
Ceiling Price: $/MMBtu $3.54 $ $ $ $
Basis Swap Contracts:
NW Rockies basis swap volume (MMBtu/d)(a) 10,333 170,000 170,000 77,174
Price differential ($/MMBtu) $(0.58) $(0.62) $(0.62) $(0.61) $

(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 Capital Investment Plan

To better balance production growth with free cash flow generation, the Company is reducing its capital budget year-over-year by approximately 30% to $400 million with the investments allocated as follows:

2018 Capital Investment Plan: ($ millions)
Pinedale Operated Vertical Development $240
Pinedale Operated Horizontal Program $120
Pinedale Non-Operated Development $30
Corporate $10
Total Capital Investments $400

“In Wyoming, production is expected to increase by 7% to 11%, driven by a reduced, but high-graded vertical drilling program, that by itself is expected to deliver $175 million of free cash flow at the asset level, and growing horizontal production. This cash flow generation, plus proceeds from the expected Utah divestiture, will help fund accelerated horizontal activity in 2018 that will be ramped up over 5 times year-over-year,” said Brad Johnson, Interim Chief Executive Officer.

2018 Guidance(1)

In 2018, the Company is focused on capital efficiency, cash flow visibility and accelerating the horizontal program, all within cash flow.

Production: Ultra’s 2018 annual production is expected to range between 280-290 Bcfe. In the first quarter, the average daily production rate is expected to range between 790-810 MMcfe/d.

Price Realizations and Differentials: During the first quarter of 2018, the Company's realized natural gas price per Mcf is expected to average 8 to 10 percent below the NYMEX price due to regional differentials, before consideration of any hedging activity. Realized pricing for oil is expected to be approximately 3 to 5 percent less than the average NYMEX crude oil price in the first quarter.

Expenses: The following table presents the Company's expected per unit of production expenses for the first quarter of 2018 assuming a $3.00 per MMBtu Henry Hub natural gas price and a $60.00 per Bbl NYMEX crude oil price:

Costs Per Mcfe 1Q 2018
Lease operating expenses $0.32 – 0.35
Facility lease expense $0.08 – 0.08
Production taxes $0.32 – 0.34
Gathering fees $0.34 – 0.36
Transportation charges $0.00 – 0.00
Depletion and depreciation $0.66 – 0.70
General and administrative-cash $0.03 – 0.06
Interest expense $0.50 – 0.51
Total costs per Mcfe $2.25 – 2.40

Income Tax: The Company does not expect any tax expense during 2018.

(1)2018 guidance assumes that the Utah properties are sold as of March 31, 2018.

Year-End 2017 Reserves

For the year-ended December 31, 2017, the Company’s reserves totaled 3.1 trillion cubic feet equivalent (Tcfe) of total proved reserves with pre-tax estimated future net cash flows discounted at ten percent (PV-10) of $2.4 billion. Natural gas represents 95 percent of the Company’s proved reserves, with 99 percent of those reserves in Wyoming.

Ultra Petroleum’s reserves were calculated based on reference prices for oil and natural gas in accordance with SEC rules. These reference prices, before differentials, were $2.98 per MMBtu Henry Hub (HHUB) for natural gas and $51.34 per Bbl West Texas Intermediate (WTI) for oil. Applying regional market differentials along with appropriate adjustments for quality, energy content and transportation charges, the average prices for the company’s proved reserves were $2.59 per Mcf for natural gas and $48.05 per Bbl for oil.

Natural Gas and Oil Reserves
December 31, 2017
Net Gas Net Oil Net
Equiv.
PV-10
(Bcf) (MMBbls) (Bcfe) ($MM)
PDP 2,231.9 21.3 2,360.4 $2,124.0
PDNP 29.4 0.3 31.2 $27.7
PUD 694.7 5.5 727.5 $232.7
Total
Proved
2,956.0 27.1 3,119.1 $2,384.4

Proved undeveloped reserves include only 4 horizontal locations (immediate offsets to producing horizontal wells at year end) of the 1,600 potential horizontal locations identified by the Company. The remaining PUD bookings include a reduced inventory of previously booked vertical PUDs in order to comport with the Company’s 5-year development plan. This 5-year plan accounts for an expected increase in drilling horizontal locations that do not currently meet SEC guidelines for proved reserves due to the early stages of this resource expansion program.

Conference Call Webcast Scheduled for February 28, 2018

Ultra Petroleum’s fourth quarter 2017 results conference call will be available via webcast at 11:00 a.m. Eastern Standard Time (10:00 a.m. Central Standard Time) Wednesday, February 28, 2018. 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 Year Ended For the Quarter Ended
December 31, December 31,
2017 2016 2017 2016
Volumes:
Natural gas (Mcf) 260,008,429 264,278,138 70,107,780 63,991,905
Oil and condensate (Bbls) 2,775,762 2,911,617 732,571 706,472
Mcfe - Total 276,663,001 281,747,840 74,503,206 68,230,737
Revenues:
Natural gas sales $748,682 $609,756 $196,885 $183,878
Oil sales 133,368 111,335 38,953 31,982
Other revenue 9,823 - 4,789 -
Total operating revenues 891,873 721,091 240,627 215,860
Expenses:
Lease operating expenses 92,326 89,134 22,961 21,970
Facility lease expense 21,749 20,686 6,043 5,171
Production taxes 91,067 69,737 24,698 20,343
Gathering fees 86,953 86,809 23,200 21,697
Total lease operating costs 292,095 266,366 76,902 69,181
Transportation charges - 20,049 - (3,701)
Depletion and depreciation 161,945 125,121 50,430 31,847
General and administrative 39,548 9,179 5,241 1,983
Total operating expenses 493,588 420,715 132,573 99,310
Other (expense) income, net (237) (3,082) (210) (644)
Restructuring expenses - (7,176) - -
Contract settlement expense (52,707) (131,106) - (131,106)
Interest expense (361,367) (66,565) (36,389) (1)
Deferred gain on sale of liquids gathering system 10,553 10,553 2,638 2,638
Realized gain on commodity derivatives 11,446 - 3,430 -
Unrealized gain (loss) on commodity derivatives 16,966 - 12,834 -
Total other (expense) income, net (375,346) (197,376) (17,697) (129,113)
Reorganization items, net 140,907 (47,503) (1,240) (22,211)
Income (loss) before income taxes 163,846 55,497 89,117 (34,774)
Income tax (benefit) provision (13,294) (654) (6,411) (349)
Net income (loss) $177,140 $56,151 $95,528 $(34,425)
Adjusted Net Income Reconciliation:
Net income (loss) $177,140 $56,151 $95,528 $(34,425)
Reorganization items, net (140,907) 47,503 1,240 22,211
Postpetition interest expense 260,517 - - -
Contract settlement expense 52,707 131,106 - 131,106
Restructuring expenses - 7,176 - -
Unrealized (gain) loss on commodity derivatives (16,966) - (12,834) -
Deferred taxes - 1 - -
Other 607 3,215 4 292
Adjusted net income(2) $333,098 $245,152 $83,938 $119,184
Operating cash flow (1) (7)(8) $524,467 $346,695 $137,524 $145,126
(see non-GAAP reconciliation)
Adjusted EBITDA(5) $612,023 $431,192 $167,502 $149,639
(see non-GAAP reconciliation)
Weighted average shares (000's)(9)
Basic 163,824 79,996 196,347 80,012
Diluted 163,976 80,363 196,347 80,012
Earnings (loss) per share(9)
Net income (loss) - basic $1.08 $0.70 $0.49 $(0.43)
Net income (loss)- diluted $1.08 $0.70 $0.49 $(0.43)


Adjusted earnings per share(2)(9)
Adjusted net income - basic $2.03 $3.06 $0.43 $1.49
Adjusted net income - diluted $2.03 $3.05 $0.43 $1.49
Realized Prices
Natural gas ($/Mcf), excluding realized gain on commodity
derivatives
$2.88 $2.31 $2.81 $2.87
Natural gas ($/Mcf), including realized gain on commodity
derivatives
$2.92 $2.31 $2.86 $2.87
Oil liquids ($/Bbl) $48.05 $38.24 $53.17 $45.27
Costs Per Mcfe
Lease operating expenses $0.33 $0.32 $0.31 $0.32
Facility lease expense $0.08 $0.07 $0.08 $0.08
Production taxes $0.33 $0.25 $0.33 $0.30
Gathering fees (net) $0.28 $0.31 $0.25 $0.32
Transportation charges $- $0.07 $- $(0.05)
Depletion and depreciation $0.59 $0.44 $0.68 $0.47
General and administrative - total $0.14 $0.03 $0.07 $0.03
Interest expense(7) $0.36 $0.24 $0.49 $-
$2.11 $1.73 $2.21 $1.47
Adjusted Margins
Adjusted Net Income Margin(3) 37% 34% 34% 55%
Adjusted Operating Cash Flow Margin(4)(7)(8) 58% 48% 56% 67%
Adjusted EBITDA Margin(6) 69% 60% 69% 69%

Ultra Petroleum Corp.
Supplemental Balance Sheet Data
All amounts expressed in US$000’s

As of
December 31, December 31,
2017 2016
(Unaudited)
Cash and cash equivalents $16,631 $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 999,000
Total long-term debt $2,175,000 $3,759,000
Less: Deferred financing costs (58,789) -
Less: Liabilities subject to compromise - (3,759,000)
Total long-term debt not subject to compromise $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 Year Ended For the Quarter Ended
December 31, December 31,
2017 2016 2017 2016
Net cash provided by operating activities $65,268 $311,071 $(83,516) $136,926
Net changes in operating assets and liabilities and other non-cash or non-recurring items(7)(8) 459,199 35,624 221,040 8,200
Operating Cash Flow (1) $524,467 $346,695 $137,524 $145,126

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 Year Ended For the Quarter Ended
December 31, December 31,
2017 2016 2017 2016
Net income (loss) $177,140 $56,151 $95,528 $(34,425)
Interest expense 361,367 66,565 36,389 1
Depletion and depreciation 161,945 125,121 50,430 31,847
Reorganization items, net (140,907) 47,503 1,240 22,211
Contract settlement expense 52,707 131,106 - 131,106
Unrealized (gain)/loss on commodity derivatives (16,966) - (12,834) -
Restructuring expenses - 7,176 - -
Deferred gain on sale of liquids gathering system (10,553) (10,553) (2,638) (2,638)
Stock compensation expense 39,977 5,562 5,795 1,594
Taxes (13,294) (654) (6,411) (349)
Other 607 3,215 3 292
Adjusted EBITDA (5) $612,023 $431,192 $167,502 $149,639

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 twelve months ended December 31, 2017, excludes postpetition interest expense that represents interest for the period beginning April 29, 2016 through April 12, 2017.

(8)For the three months and year ended December 31, 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.

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 400 N. Sam Houston Parkway E., 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.

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 proved reserves. There are numerous uncertainties inherent in estimating proved reserves, including projecting future rates of production and timing of development. Because of these and other factors, the quantities of oil and gas ultimately recovered by the Company may be materially different from the estimates of reserves in this news release. In addition, the SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. The Company is strictly prohibited from using other terms such as “estimated ultimate recovery” or “EUR” or “resource potential” or similar terms are used by oil and gas companies from time to time in news releases or investor presentations. These types of estimates do not represent and are not intended to represent any category of reserves based on SEC definitions, do not comply with guidelines established by the American Institute of Certified Public Accountants regarding forecasts of oil and gas reserve estimates, are, by their nature, more speculative than estimates of proved, probable and possible reserves disclosed in SEC filings, and, accordingly, are subject to substantially greater uncertainty of being actually realized. Actual volumes or quantities of oil and gas that may be ultimately recovered will likely differ substantially from these estimates. 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, weather and government regulation, and the availability of oil field services, personnel and equipment.

For further information contact:
Sandi Kraemer
Director, Investor Relations
Phone: 281-582-6613
Email: skraemer@ultrapetroleum.com

Source:Ultra Petroleum Corp.