Ultra Petroleum 8K Announces Second Quarter 2018 Results, Provides Update on Horizontal and Vertical Program | SEC 9 Aug 18

EXHIBIT 99.1

Ultra Petroleum Announces Second Quarter 2018 Results, Provides Update on Horizontal and Vertical Program

HOUSTON, Aug. 09, 2018 (GLOBE NEWSWIRE) -- Ultra Petroleum Corp. (NASDAQ: UPL) announces financial and operating results for the quarter ended June 30, 2018.

Financial and Operating Highlights:

Second quarter production of 70.9 Bcfe increased 6% compared to second quarter 2017,
Drilled and completed 11 horizontal wells targeting multiple intervals within the Lower Lance formation,
Increased intervals within the Lower Lance formation from four to five, with each interval further subdivided into two distinct zones to land horizontals,
The six horizontal wells the Company drilled in the Lower Lance A1 zone (90 feet below the top of the Lower Lance) had an average 24-hour IP rate of 27.3 MMcfe/d with other targeted zones providing more variable results,
Brought 18 vertical wells online with highest average 24-hour IP rate over the last seven quarters at 8.8 MMcfe/d,
Plan to run 3 operated rigs (1 horizontal and 2 vertical) for remainder of 2018 to focus on free cash flow generation until gas pricing improves, and
Additional financial and operating highlights can be found in the new investor presentation posted at www.ultrapetroleum.com.

Second Quarter 2018 Financial Results

During the second quarter of 2018, total revenues were $190.1 million as compared to $212.7 million during the second quarter of 2017. The Company’s production of natural gas and oil was 70.9 billion cubic feet equivalent (Bcfe), an increase of 6% over the second quarter of 2017, with 66.9 billion cubic feet (Bcf) of natural gas and 667.0 thousand barrels (MBbls) of oil and condensate.

During the second quarter of 2018, Ultra Petroleum’s average realized natural gas price was $2.28 per thousand cubic feet (Mcf), which includes realized gains and losses on commodity hedges and compares to $2.84 for the same period in 2017. Excluding the realized gains and losses from commodity derivatives, the Company’s average price for natural gas was $2.11 per Mcf, compared to $2.85 per Mcf for the second quarter of 2017. The Company’s average realized oil and condensate price was $58.24 per barrel (Bbl), which includes realized losses on commodity hedges, for the quarter ended June 30, 2018. Excluding the realized losses from oil commodity derivatives, the Company’s average price for oil was $64.71 per Bbl as compared to $45.51 per Bbl for the same period in 2017.

Ultra Petroleum’s reported net loss was $20.6 million, or $0.10 per diluted share. Ultra reported adjusted net income⁽²⁾ of $34.0 million, or $0.17 per diluted share for the quarter ended June 30, 2018.

Year-to-Date Financial Results

During the six months ended June 30, 2018, total revenues were $415.5 million as compared to $433.6 million during the same period in 2017. During the first six months of 2018, the Company’s production of natural gas and oil was 143.2 Bcfe, an increase of 9% over 2017, with 135.1 Bcf of natural gas and 1.3 million barrels (MMBbls) of oil and condensate.

During the first six months of 2018, Ultra Petroleum’s average realized natural gas price was $2.48 per Mcf, which includes realized gains and losses on commodity hedges and compares to $2.99 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 $2.39 per Mcf, compared to $3.00 per Mcf for the six months ended June 30, 2017. The Company’s average realized oil and condensate price was $59.31 per Bbl, which includes realized losses on commodity hedges, for the six months ended June 30, 2018. Excluding the realized losses from oil commodity derivatives, the Company’s average price for oil was $62.79 per Bbl as compared to $46.39 per Bbl for the same period in 2017.

Ultra Petroleum’s reported net income was $26.9 million, or $0.14 per diluted share. Ultra reported adjusted net income⁽²⁾ of $89.3 million, or $0.45 per diluted share for the six months ended June 30, 2018.

Pinedale Horizontal Program

Through the Company’s horizontal delineation program, Ultra Petroleum has now designated five intervals within the Lower Lance: Lower Lance A through E. Ultra has subdivided each interval into an upper and lower zone, which it refers to as 1 and 2, respectively.

In the second quarter, Ultra focused its delineation efforts on the Lower Lance formation with the completion of 11 gross (8.1 net) horizontal wells, targeting four different zones within the Lower Lance. Four of these wells were drilled in the Lower Lance A1 zone (90 feet below the top of the formation), four were drilled in the Lower Lance A2 zone (250 feet below the top of the formation), two were drilled in the Lower Lance C1 zone (690 feet below the top of the formation) and one was drilled in the Lower Lance E1 zone (1,290 feet below the top of the formation).

A total of six wells are now producing from the Lower Lance A1 zone (90 feet below the top of the formation) with an average 24-hour initial production (IP) rate of approximately 27.3 million cubic feet of natural gas equivalent per day (MMcfe/d).

A total of four wells are now producing from the Lower Lance A2 zone (250 feet below the top of the formation) with an average 24-hour IP rate of 8.0 MMcfe/d.

The Company also drilled two wells in the Lower Lance C1 zone (690 feet below the top of the formation) with an average 24-hour IP rate of 12.1 MMcfe/d.

At the end of the second quarter, the Company began producing its first Lower Lance E1 zone well (1,290 feet below the top of the formation) with a 24-hour IP rate of 11.3 MMcfe/d.

The table below provides details on each Lower Lance horizontal well brought online since November 2017, along with the average results by zone:


Well	Target Zone	IP Prod Date	Lateral Length	Net/Gross %		Stage Count	IP 24h Rate, MMcfe/d	IP30, MMcfe/d	IP Yield BBl/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 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

WB 8-14 3H	Lower Lance C1	May-18	7,510	81	%	35	20,021	11,645	26.0
WB 9-23 11H	Lower Lance C1	Jun-18	10,821	45	%	25	4,107	2,718	18.5

WB 8-14 4H	Lower Lance E1	Jun-18	6,863	40	%	16	11,318	6,332	33.0

Lower Lance A1 Average			8,841	70	%	39	27,325	18,290	16.1
Lower Lance A2 Average			9,448	48	%	34	8,043	5,228	12.1
Lower Lance C1 Average			9,166	63	%	29	12,064	7,092	22.3
Lower Lance E1 Average			6,863	40	%	16	11,318	6,332	33.0

“Ultra is in the beginning stages of developing the Pinedale field with horizontal wells. While we anticipated variable results, and had some encouraging results from multiple zones, overall the average performance of these wells in the second quarter was below expectations. We are expanding our technical efforts to better leverage our learnings in future horizontal wells. With 78,000 net acres and an operating team that has drilled more than 2,100 vertical wells in Pinedale, we are uniquely positioned to lead this effort, but it will take time and patience as we delineate Pinedale’s significant horizontal potential,” said Ultra Petroleum Interim Chief Executive Officer, Brad Johnson.

Pinedale Vertical Program

During the second quarter, the Company and its partners brought online 18 gross (10.6 net) vertical wells in Pinedale. The average 24-hour IP rate for new operated vertical wells brought online in the second quarter of 2018 was 8.8 MMcfe per day.

“During the second quarter of 2018, we posted the highest average IPs for our vertical wells in the last seven quarters. With a large, high quality inventory of vertical locations, we will continue to execute on a solid, returns-driven vertical program,” said Ultra Petroleum Chief Operating Officer, Jay Stratton.

Hedging Activity

The table below provides a summary of the hedges in place as of August 7, 2018:


NYMEX	Q3 2018			Q4 2018				Q1 2019			Q2 2019			Q3 2019			Q4 2019			Q1 2020
Natural Gas Swaps:
Volume (MMBtu/d)		770,000			657,283				660,000			400,000			380,000			360,000			170,000
$/MMBtu	$	2.88		$		2.88		$	2.92		$	2.75		$	2.76		$	2.77		$	2.76

Oil Swaps:
Volume (Bbl/d)		6,500				6,500			6,000			6,000			4,000			3,000			1,000
$/Bbl	$	60.61		$		60.45		$	58.46		$	59.16		$	58.59		$	59.23		$	60.05

Basis Swap Contracts:
NW Rockies basis swap volume (MMBtu/d)^(a)financial		562,500				559,674			572,500			120,000			120,000			120,000			—
NW Rockies basis swap volume (MMBtu/d)^(a)physical		170,000				57,283			—			—			—			—			—
Price differential ($/MMBtu)	$	(0.65	)	$		(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 recently reduced its operated rig count from four to three. Two rigs are currently focused on vertical development and one rig is currently focused on horizontal development.

Production: The Company is adjusting annual production guidance down to 273 to 283 Bcfe. In the third quarter, the average daily production rate is expected to range between 710-750 MMcfe/d.

Capital Investment: The Company is affirming its 2018 total capital budget of $400 million.

Expenses: The following table presents the Company's expected per unit of production expenses for the third quarter of 2018. Production tax guidance assumes a $2.86 per MMBtu Henry Hub natural gas price and a $68.00 per Bbl NYMEX crude oil price:


Costs Per Mcfe		3Q 2018
Lease operating expenses	$	0.30 – 0.34
Facility lease expense	$	0.08 – 0.10
Production taxes	$	0.30 – 0.32
Gathering fees, net	$	0.24 – 0.26
Transportation charges	$	0.00 – 0.00
Depletion and depreciation	$	0.72 – 0.76
General and administrative-cash	$	0.01 – 0.03
Interest expense	$	0.54 – 0.56

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

Asset Sale

Subsequent to the quarter end, the Company entered into a Purchase and Sale Agreement to sell all of its Utah assets for cash consideration of $75 million, subject to customary closing adjustments. The transaction is expected to close during the third quarter of 2018. During the quarter ended June 30, 2018, the Company’s Utah assets produced approximately 2,000 barrels of oil equivalent per day.

Conference Call Webcast Scheduled for August 9, 2018

Ultra Petroleum’s second quarter 2018 results conference call will be available via webcast at 11:00 a.m. Eastern Daylight Time (10:00 a.m. Central Daylight Time) Thursday, August 9, 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 Six Months Ended						For the Quarter Ended
	June 30,						June 30,
	2018			2017			2018			2017
Volumes:
Natural gas (Mcf)		135,126,814			123,056,200			66,892,949			63,066,779
Oil and condensate (Bbls)		1,344,880			1,338,133			667,038			675,236
Mcfe - Total		143,196,094			131,084,998			70,895,177			67,118,195

Revenues:
Natural gas sales	$	322,716		$	368,848		$	141,255		$	179,997
Oil sales		84,451			62,081			43,167			30,732
Other revenue		8,344			2,687			5,716			1,928
Total operating revenues		415,511			433,616			190,138			212,657

Expenses:
Lease operating expenses		45,409			46,225			23,645			23,089
Facility lease expense		12,682			10,452			6,526			5,226
Production taxes		42,153			43,887			18,883			21,754
Gathering fees		47,238			41,571			24,181			20,642
Total lease operating costs		147,482			142,135			73,235			70,711

Depletion and depreciation		102,282			70,427			51,742			38,673
General and administrative		14,752			26,061			2,063			25,009
Total operating expenses		264,516			238,623			127,040			134,393

Other (expense) income, net		(1,541	)		(119	)		(1,296	)		27
Contract settlement expense		—			(52,707	)		—			—
Interest expense		(73,552	)		(114,872	)		(37,715	)		(29,425	)
Deferred gain on sale of liquids gathering system		5,276			5,276			2,638			2,638
Realized gain (loss) on commodity derivatives		7,736			(868	)		6,662			(868	)
Unrealized gain (loss) on commodity derivatives		(61,539	)		8,367			(53,933	)		21,585
Total other (expense) income, net		(123,620	)		(154,923	)		(83,644	)		(6,043	)

Reorganization items, net		—			369,270			—			426,816

Income (loss) before income taxes		27,375			409,340			(20,546	)		499,037
Income tax provision		442			2			9			—

Net income (loss)	$	26,933		$	409,338		$	(20,555	)	$	499,037

Adjusted Net Income Reconciliation:
Net income (loss)	$	26,933		$	409,338		$	(20,555	)	$	499,037
Reorganization items, net		—			(369,270	)		—			(426,816	)
Postpetition interest expense		—			85,338			—			460
Contract settlement expense		—			52,707			—			—
Unrealized loss (gain) on commodity derivatives		61,539			(8,367	)		53,933			(21,585	)
Other		853			583			639			(80	)
Adjusted net income ⁽²⁾	$	89,325		$	170,329		$	34,017		$	51,016

*Operating cash flow ^{(1) (7)(8)}*	$	196,453		$	261,744		$	84,432		$	112,464
*(see non-GAAP reconciliation)*

*Adjusted EBITDA ⁽⁵⁾*	$	270,447		$	291,279		$	122,156		$	141,889
*(see non-GAAP reconciliation)*

Weighted average shares (000's) ⁽⁹⁾
Basic		196,803			130,770			197,054			180,964
Diluted		196,803			131,078			197,054			181,033

Earnings (loss) per share
Net income (loss) - basic	$	0.14		$	3.13		$	(0.10	)	$	2.76
Net income (loss)- diluted	$	0.14		$	3.12		$	(0.10	)	$	2.76


Adjusted earnings per share ^{(2) (9)}
Adjusted net income - basic	$	0.45	$	1.30	$	0.17	$	0.28
Adjusted net income - diluted	$	0.45	$	1.30	$	0.17	$	0.28

Realized Prices
Natural gas ($/Mcf), excluding realized gain on commodity derivatives	$	2.39	$	3.00	$	2.11	$	2.85
Natural gas ($/Mcf), including realized gain on commodity derivatives	$	2.48	$	2.99	$	2.28	$	2.84
Oil liquids ($/Bbl), excluding realized gain on commodity derivatives	$	62.79	$	46.39	$	64.71	$	45.51
Oil liquids ($/Bbl), including realized gain on commodity derivatives	$	59.31	$	46.39	$	58.24	$	45.51

Costs Per Mcfe
Lease operating expenses	$	0.32	$	0.35	$	0.33	$	0.34
Facility lease expense	$	0.09	$	0.08	$	0.09	$	0.08
Production taxes	$	0.29	$	0.33	$	0.27	$	0.32
Gathering fees (net)	$	0.27	$	0.32	$	0.26	$	0.31
Depletion and depreciation	$	0.71	$	0.54	$	0.73	$	0.58
General and administrative - total	$	0.10	$	0.20	$	0.03	$	0.37
Interest expense ⁽⁷⁾	$	0.51	$	0.23	$	0.53	$	0.43
	$	2.29	$	2.05	$	2.24	$	2.43
Adjusted Margins
Adjusted Net Income Margin ⁽³⁾		21%		39%		17%		24%
Adjusted Operating Cash Flow Margin ^(4)(7)(8)		46%		60%		43%		53%
Adjusted EBITDA Margin ⁽⁶⁾		64%		67%		62%		67%

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

	As of
	June 30,			December 31,
	2018			2017
	(Unaudited)
Cash and cash equivalents	$	5,685		$	16,631
Long-term debt:
Term Loan, secured due 2024		972,563			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		58,000			—
Long-term debt	$	2,230,563		$	2,175,000
Less: Deferred financing costs		(54,155	)		(58,789	)
Total long-term debt	$	2,176,408		$	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 Six Months Ended					For the Quarter Ended
	June 30,					June 30,
	2018			2017		2018		2017
Net cash provided by operating activities	$	205,781		$	136,461	$	53,785	$	(34,971	)
Net changes in operating assets and liabilities and other non-cash or non-recurring items ⁽⁷⁾⁽⁸⁾		(9,328	)		125,283		30,647		147,435
Operating Cash Flow ⁽¹⁾	$	196,453		$	261,744	$	84,432	$	112,464

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 Six Months Ended						For the Quarter Ended
	June 30,						June 30,
	2018			2017			2018			2017
Net income (loss)	$	26,933		$	409,338		$	(20,555	)	$	499,037
Interest expense		73,552			114,872			37,715			29,425
Depletion and depreciation		102,282			70,427			51,742			38,673
Reorganization items, net		—			(369,270	)		—			(426,816	)
Contract settlement expense		—			52,707			—			—
Unrealized (gain) loss on commodity derivatives		61,539			(8,367	)		53,933			(21,585	)
Deferred gain on sale of liquids gathering system		(5,276	)		(5,276	)		(2,638	)		(2,638	)
Stock compensation expense		10,122			26,264			1,311			25,413
Taxes		442			2			9			—
Houston office relocation		564			—			564			—
Other		289			582			75			380
Adjusted EBITDA ⁽⁵⁾	$	270,447		$	291,279		$	122,156		$	141,889

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 quarter and six months ended June 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 six months ended June 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 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 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. 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 the Company's most recent Annual Report on Form 10-K for the most recent fiscal year, 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: IR@ultrapetroleum.com

Ultra Petroleum 8-KUltra Petroleum Announces Second Quarter 2018 Results, Provides Update on Horizontal and Vertical Program