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Ultra Petroleum Corp. Announces Second Quarter 2019 Results Outperforming Guidance on Production and Controllable Cash Costs and Provides Operations Update with Decision to Reduce Capital Expenditures by Reducing Activity to a Single Operated Drilling Rig


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Source: Ultra Petroleum Corp.

ENGLEWOOD, Colo., Aug. 09, 2019 (GLOBE NEWSWIRE) — Ultra Petroleum Corp. (“Ultra Petroleum” or the “Company”) (OTCQX: UPLC) announces financial and operating results for the quarter ended June 30, 2019.

Financial and Operating Highlights:

  • Second quarter production was 62.5 billion cubic feet equivalent (“Bcfe”), above guidance,
  • The Company brought 26 gross (26.0 net) operated vertical wells online with average 24-hour initial production (IP) rates of 6.3 Million cubic feet equivalent per day (“MMcfe/d”),
  • Second quarter vertical well cost averaged $3.2 million,
  • The Company continues to move forward with its 2-string wellbore design pilot program and successfully drilled and completed 8 wells at an average cost of $2.6 million,
  • Total controllable cash costs, which is the summation of LOE per Mcfe and cash general and administrative costs per Mcfe, was $0.34 per Mcfe, at the low end of guidance,
  • Subsequent to quarter end, the Company decided to drop to one operated rig and expects positive free cash flow beginning in the third quarter of this year,
  • Additional financial and operating highlights can be found in the new investor presentation posted at www.ultrapetroleum.com.

“Production exceeded guidance for the quarter and controllable cash costs were on the low end of guidance, driven by a significant beat in LOE at $0.25/mcfe. These results were accomplished by a focused and dedicated team and highlights our ability to continuously achieve incremental improvement to our Pinedale operations,” said Ultra Petroleum’s Chief Executive Officer Brad Johnson.

Capital Investment Update

In May 2019, the Company elected to decrease its operated rig count from three to two rigs, in response to natural gas price forecast at the time. The impact to full year production was somewhat muted in that the Company improved the drilling time for new wells and enjoyed a higher working interest in the wells drilled in the first half of the year.

In the third quarter, the Company plans to reduce its operated drilling program to a single rig. This will further reduce the level of total capital investment in 2019 to approximately $260 – $290 million, a reduction of approximately $60 million, or 18%, from the midpoint of the Company’s initial full year capital investment guidance.  With this revision, the updated production guidance for the full year 2019 is slightly reduced to 238 to 244 Bcfe, a reduction of 4 Bcfe, or less than 2%, from the midpoint of the Company’s initial production guidance.  With these changes, and in spite of forecast strip pricing for natural gas, the Company expects to generate free-cash flow in both the third and fourth quarters of 2019.

“Moving to a one-rig operated drilling program is a prudent decision in the current natural gas price environment. We will continue to exercise capital discipline and adjust our investment levels accordingly.  Additionally, our Pinedale asset continues to deliver large-scale production with strong operating margins delivered from our long-lived low-decline asset,” said Mr. Johnson.

Pinedale Vertical Program

During the second quarter, the Company brought online 26 gross (26.0 net) vertical wells in Pinedale. The average 24-hour IP rate for new operated vertical wells brought online in the quarter was 6.3 MMcfe/d.  The Company also participated in 10 gross (3.3 net) non operated vertical wells in Pinedale.

The average cost of vertical wells drilled in the quarter was $3.2 million, which included 15 wells drilled with a 3-string design and 11 wells designed with 2-strings of casing. The Company delivered 8 successful 2-string design wells at an average cost of $2.6 million per well. Three additional 2-string design wells required a 3-string contingency option.  Overall these results reflect an increasing success rate for the 2-string design to 73%, up from 50% last quarter.  Additionally, the successful 2-string designs reduced cost by $0.5 million, 20% more than the $0.4 million savings recorded last quarter.  All-in average well costs in the second quarter for the eleven wells designed for 2-strings program was $2.9 million.     The continued execution of the vertical 2-string wellbore design pilot program is providing incremental support for the potential economic improvement using this drilling design.

Pinedale Horizontal Update

The Company continues to evaluate its horizontal program including data and advanced technical evaluations from Pinedale horizontal wells drilled to date. The technical work is providing a benefit to the understanding of the horizontal well potential and is also demonstrating it has applications to enhance the predictability of the Company’s vertical well program.

Second Quarter Financial Results

During the second quarter of 2019, total production volumes were 62.5 Bcfe, a 0.3 Bcfe uplift from the first quarter production volumes of 62.2 Bcfe. Production was 12% lower than the 70.9 Bcfe recorded in the same quarter of 2018. Continued operational efficiency allowed the Company to produce above its expected guidance even as it reduced overall capital investment to optimize cash flow and liquidity in the face of a challenging regional gas pricing.  Second quarter 2019 production was comprised of 59.8 billion cubic feet (Bcf) of natural gas and 449.2 thousand barrels (MBbls) of oil and condensate. Natural gas production was 11% lower and oil production was 33% lower than the comparable period in 2018.

Total revenues decreased 18% to $155.4 million as compared to $190.1 million during the second quarter of 2018 based on lower production in the second quarter of 2019 and lower oil pricing. The net realized price in the quarter ended June 30, 2019 was $2.45 per Mcfe, excluding derivative settlements, and $2.51 per Mcfe, including the effect of derivatives.  Realized pricing was $2.60 per Mcfe, excluding derivative settlements, and $2.70 per Mcfe including the settlements of derivatives. Total derivative settlements during the second quarter of 2019 were $3.4 million compared to $6.6 million in the same period of 2018.

During the second quarter of 2019, Ultra Petroleum’s average realized natural gas price was $2.17 per Mcf, which includes realized gains on derivative settlements. Excluding the realized gains from derivatives, the Company’s average price for natural gas was $2.11 per Mcf, flat as compared to the second quarter of 2018. The Company’s average realized oil and condensate price, including derivative settlements, was $59.65 per barrel (Bbl) for the quarter ended June 30, 2019 as compared to $58.24 per Bbl for the same period in 2018.

Ultra Petroleum’s reported net income was $57.1 million, or $0.29 per diluted share.  Ultra reported adjusted net income(1) of $4.1 million, or $0.02 per diluted share for the quarter ended June 30, 2019.

Year-to-Date Financial Results

Year-to-date revenues from natural gas and oil sales, including processing credits, increased to $426.9 million for the six months ended June 30, 2019, as compared to $415.5 million in 2018.  During the six months ended June 30, 2019, production of natural gas and oil was 124.7 Bcfe, which was comprised of 119.4 Bcf of natural gas and 886 MBbl of oil.

During the six months ended June 30, 2019, Ultra’s average realized natural gas price was $2.47 per Mcf, including derivative settlements. Excluding the derivative settlements, the Company’s average price for natural gas was $3.12 per Mcf compared to $2.39 per Mcf for the same period in 2018. The Company’s average realized oil price, not including derivative settlements, was $57.30 per Bbl for the six months ended June 30, 2019, as compared to $62.97 per Bbl for the same period in 2018.

For the six months ended June 30, 2019, total capital expenditures were $176.8 million. During this period, the Company turned to sales 53 gross (52.5 net) operated vertical wells and 1 gross (0.9 net) horizontal well.  Additionally, there were 16 gross (5.3 net) vertical wells operated by others that were turned to sales in the Pinedale field in Wyoming.

Ultra’s reported net income for the six months ended June 30, 2019, was $97.8 million, or $0.49 per diluted share as compared with net income of $26.9 million or $0.14 per diluted share for the same period in 2018.  Adjusted net income for the six months ended June 30, 2019, was $31.3 million, or $0.16 per diluted share, as compared to $89.3 million and $0.45 per diluted share in 2018.

Hedging Activity

The Company continued to hedge in order to provide a degree of certainty of cash flows and maintain compliance under its revolving credit facility. Management has worked to balance the ability to provide upside exposure for the Company as the increase in future commodity prices has a meaningful impact on its cash flows given its low operating costs. This is demonstrated by the Company placing new derivative contracts using predominately costless collars and deferred premium put contracts. The Company has also continued to layer in basis swaps on a methodical and prudent manner through the winter season 2019/2020.

The table below provides a summary of the hedges in place as of July 31, 2019:

Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 Q1 2021
Natural Gas Swaps:
Volume (MMBtu/d) 412,228 355,000 270,000
NYMEX ($/MMBtu) $ 2.75 $ 2.77 $ 2.78 $ $ $ $   —
Natural Gas Collars:
Volume (MMBtu/d) 15,000 15,000 130,000 236,000 175,000 290,000   80,000
NYMEX Floor ($/MMBtu) $ 2.80 $   2.90 $ 2.78 $ 2.35 $ 2.41 $ 2.44 $   2.46
NYMEX Ceiling ($/MMBtu) $ 3.10 $ 3.15 $ 3.23 $ 2.83 $ 2.85 $ 2.91 $   3.05
Natural Gas Puts:
Volume (MMBtu/d) 114,000 160,000 30,000
NYMEX Strike Price ($/MMBtu) $ $ $ $ 2.35 $ 2.41 $ 2.44 $   —
Oil Swaps:
Volume (Bbl/d) 4,000 3,500 2,500 1,500 1,000
NYMEX ($/Bbl) $ 58.59 $ 59.88 $ 60.42 $ 60.33 $ 60.00 $ $   —
Natural Gas Basis Swap Contracts:
NW Rockies Volume (MMBtu/d)(a) 420,000 296,793 158,187
Price Differential ($/MMBtu) $ (0.55 ) $ (0.49 ) $ (0.17 ) $ $ $ $   —

(a) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming.

2019 Guidance

The following updates are provided for the full year and third quarter of 2019:

Capital Investments: The updated capital investment guidance of $260 – $290 million reflects the decision to transition to a one-rig operated drilling program in September 2019.

Production: Considering the Company’s revised capital investment guidance, the updated production guidance for the full year 2019 is narrowed and slightly reduced to 238 to 244 Bcfe.  In the third quarter, the average daily production rate is expected to range between 635 to 655 MMcfe/d.

Expense: The following table presents the Company’s expected per unit production expenses for full year and the third quarter of 2019. Production tax guidance assumes a $2.22 and $2.70 per MMBtu Henry Hub natural gas price and a $55.57 and $56.09 per Bbl NYMEX crude oil price in the third quarter and full-year 2019, respectively.

2019 Expenses (per Mcfe) 3Q19 Guidance Full-Year 2019 Guidance
Lease Operating Expense $0.27 – 0.31 $0.26 – 0.30
Facility Lease Expense $0.10 – 0.12 $0.10 – 0.12
Production Taxes $0.24 – 0.30 $0.30 – 0.34
Gathering Fees, Gross
Gathering Fees, net
$0.31 – 0.35
$0.27 – 0.31
$0.31 – 0.35
$0.27 – 0.31
Transportation Charges $0.00 – 0.00 $0.00 – 0.01
Cash G&A $0.07 – 0.10 $0.08 – 0.11
DD&A $0.85 – 0.90 $0.85 – 0.90
Cash Interest Expense $0.58 – 0.63 $0.58 – 0.62

Conference Call and Webcast

The Company will host a conference call Friday, August 9, 2019, at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Daylight Time) to discuss the Company’s second quarter 2019 results. There will be prepared remarks from the Company’s management, followed by a question and answer session.

Investors and analysts are invited to participate in the call by dialing 1 (877) 371-5742, or 1 (629) 228-0726 for international calls, and using Conference ID: 9348319. 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.

Ultra Petroleum Corp.
Selected Operating and Financial Data
All amounts expressed in US$000’s, except per share data

  For the Six Months Ended     For the Quarter Ended  
  June 30,     June 30,  
  2019     2018     2019     2018  
Volumes:
Natural gas (Mcf) 119,380 135,128 59,805 66,892
Oil and condensate (Bbls) 886 1,345 449 667
Mcfe – Total 124,696 143,198 62,499 70,894
Revenues:
Natural gas sales $ 371,903 $ 322,716 $ 125,915 $ 141,255
Oil sales 50,767 84,451 27,301 43,167
Other revenue 4,197 8,344 2,190 5,716
Total operating revenues 426,867 415,511 155,406 190,138
Expenses:
Lease operating expenses 33,114 45,409 15,889 23,645
Facility lease expense 13,188 12,682 6,543 6,526
Production taxes 46,618 42,153 16,443 18,883
Gathering fees 40,200 47,238 20,320 24,181
Total lease operating costs 133,120 147,482 59,195 73,235
Depletion and depreciation 107,422 102,282 55,768 51,742
General and administrative 14,485 14,752 7,433 2,063
Other operating expenses, net 16,085 853 15,281 639
Total operating expenses 271,112 265,369 137,677 127,679
Other (expense) income, net 243 (688 ) (43 ) (657 )
Interest expense (65,703 ) (73,552 ) (32,376 ) (37,715 )
Deferred gain on sale of liquids gathering system 5,276 2,638
Realized gain (loss) on commodity derivatives (75,211 ) 7,736 3,420 6,662
Unrealized gain (loss) on commodity derivatives 82,527 (61,539 ) 68,234 (53,933 )
Total other (expense) income, net (58,144 ) (122,767 ) 39,235 (83,005 )
Income (loss) before income taxes 97,611 27,375 56,964 (20,546 )
Income tax provision (169 ) 442 (141 ) 9
Net income (loss) $ 97,780     $ 26,933     $ 57,105     $ (20,555 )
                               
Adjusted Net Income Reconciliation:
Net income (loss) $ 97,780     $ 26,933     $ 57,105     $ (20,555 )
Unrealized (gain) loss on commodity derivatives (82,527 ) 61,539 (68,234 ) 53,933
Other operating expense, net 16,085 853 15,281 639
Adjusted net income (1) $ 31,338     $ 89,325     $ 4,152     $ 34,017  
Operating cash flow (2) (7) $ 147,242 $ 196,453 $ 64,141 $ 84,432
(see non-GAAP reconciliation)
 
Adjusted EBITDA (5) $ 208,854 $ 270,447 $ 94,053 $ 122,156
(see non-GAAP reconciliation)
 
Weighted average shares (000’s)
Basic 197,449 196,803 197,514 197,054
Diluted 198,089 196,803 198,069 197,054
Earnings (loss) per share
Net income (loss) – basic $ 0.50 $ 0.14 $ 0.29 $ (0.10 )
Net income (loss) – diluted $ 0.49 $ 0.14 $ 0.29 $ (0.10 )
Adjusted earnings per share (1)
Adjusted net income – basic $ 0.16 $ 0.45 $ 0.02 $ 0.17
Adjusted net income – diluted $ 0.16 $ 0.45 $ 0.02 $ 0.17
Realized Prices
Natural gas ($/Mcf), excluding realized gain on commodity derivatives $ 3.12 $ 2.39 $ 2.11 $ 2.11
Natural gas ($/Mcf), including realized gain on commodity derivatives $ 2.47 $ 2.48 $ 2.17 $ 2.28
Oil liquids ($/Bbl), excluding realized gain on commodity derivatives $ 57.30 $ 62.79 $ 60.80 $ 64.71
Oil liquids ($/Bbl), including realized gain on commodity derivatives $ 59.62 $ 59.31 $ 59.65 $ 58.24
Costs Per Mcfe
Lease operating expenses $ 0.27 $ 0.32 $ 0.25 $ 0.33
Facility lease expense $ 0.11 $ 0.09 $ 0.10 $ 0.09
Production taxes $ 0.37 $ 0.29 $ 0.26 $ 0.27
Gathering fees (net) $ 0.29 $ 0.27 $ 0.29 $ 0.26
Depletion and depreciation $ 0.86 $ 0.71 $ 0.89 $ 0.73
General and administrative – total $ 0.12 $ 0.10 $ 0.12 $ 0.03
Interest expense $ 0.53 $ 0.51 $ 0.52 $ 0.53
$ 2.55 $ 2.29 $ 2.43 $ 2.24
Adjusted Margins
Adjusted Net Income Margin (3) 9 % 21 % 3 % 17 %
Adjusted Operating Cash Flow Margin (4)(7) 42 % 46 % 40 % 43 %
Adjusted EBITDA Margin (6) 59 % 64 % 59 % 62 %
  As of  
  June 30,     December 31,  
  2019     2018  
  (Unaudited)        
Cash and cash equivalents $ 5,191 $ 17,014
Outstanding debt
Credit facility 59,000 104,000
Term Loan, secured due 2024 973,247 975,000
Second Lien Notes, secured, due 2024 578,072 545,000
6.875% Senior Notes, unsecured due 2022 150,439 195,035
7.125% Senior Notes, unsecured due 2025 225,000 225,000
Outstanding debt 1,985,758 2,044,035
Net debt outstanding $ 1,980,567 $ 2,027,021
Outstanding debt $ 1,985,758 $ 2,044,035
Add: Unamortized Premium 225,085 228,096
Less: Deferred financing costs (51,635 ) (56,650 )
Total outstanding debt, per financial statements $ 2,159,208 $ 2,215,481
For the Six Months Ended     For the Quarter Ended
  June 30,     June 30,
  2019     2018     2019     2018
Net cash provided by operating activities $ 215,125   $ 205,781   $ 215,125   $ 53,785
Net changes in operating assets and liabilities and other non-cash or non-recurring items (7) (67,883 ) (9,328 ) (150,984 ) 30,647
Operating Cash Flow (2) $ 147,242 $ 196,453 $ 64,141 $ 84,432
For the Six Months Ended     For the Quarter Ended  
  June 30,     June 30,  
  2019     2018     2019     2018  
Net income $ 97,780     $ 26,933     $ 57,105     $ (20,555 )
Interest expense 65,703 73,552 32,376 37,715
Depletion and depreciation 107,422 102,282 55,768 51,742
Unrealized (gain) loss on commodity derivatives (82,527 ) 61,539 (68,234 ) 53,933
Deferred gain on sale of liquids gathering system (5,276 ) (2,638 )
Stock compensation expense 1,521 10,122 681 1,311
Debt exchange expenses 3,039 1,217
Taxes (169 ) 442 (141 ) 9
Other expenses 16,085 853 15,281 639
Adjusted EBITDA (5) $ 208,854 $ 270,447 $ 94,053 $ 122,156
Production (Mcfe) 124,696 143,196 62,499 70,895
Adjusted EBITDA per Mcfe $ 1.67 $ 1.89 $ 1.50 $ 1.72

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. Adjusted Net Income is defined as Net income adjusted to exclude non-cash mark-to-market gains or losses on commodity derivatives, certain income or expense amounts in order to exclude the volatility associated with the effects of non-recurring charges such as contract settlement expenses and other expenses.
  2. 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.
  3. Adjusted Net Income Margin is defined as Adjusted Net Income divided by Total operating revenues plus Realized gain (loss) on commodity derivatives.
  4. Adjusted Operating Cash Flow Margin is defined as Operating Cash Flow divided by Total operating revenues plus Realized gain (loss) on commodity derivatives.
  5. Earnings before interest, taxes, depletion and amortization (Adjusted EBITDA) is defined as Net income (loss) adjusted to add back 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.
  7. For the six months and quarter ended June 30, 2019 and 2018, contract settlement expense are considered non-recurring items and are excluded from operating cash flow.

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 OTCQX and trades under the ticker symbol “UPLC”.

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 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, the Company’s ability to decrease its leverage or fixed costs, 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]



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