Ultra Petroleum Corp. Announces Fourth Quarter and Full-year 2019 Results

Source Company Press Release
Company PureWest Energy LLC
Tags Corporate: Corporate Results, Guidance, Overview/Strategy, Country: Canada, United States, Financial - Costs & Metrics: Capital Expenditures, Hedging
Date April 14, 2020

Ultra Petroleum Corp. ("Ultra” or the “Company”) (OTCQX: UPLC) announces financial and operating results for the quarter and year ended December 31, 2019. The Company is also reporting proved reserves as of year-end December 31, 2019 and as of March 31, 2020.

Highlights:

  • Fourth quarter and full-year 2019 production were within guidance at 55.4 billion cubic feet equivalent (“Bcfe”) and 240.2 Bcfe, respectively,
  • During 2019, Ultra turned online 71 gross (70.3 net) operated vertical wells prior to suspending its drilling program in September,
  • The Company’s average unhedged price for natural gas was $2.78 per Mcf in the fourth quarter of 2019 and reflects that first-of-month Rockies basis was positive to Henry Hub by $0.27 per MMBtu in the fourth quarter,
  • During the fourth quarter of 2019, the Company had cash flow from operating activities of $19.8 million and generated positive free cash flow(8) of $56.4 million.

“We continue to execute on our plan of focusing on free cash flow generation and reducing our debt levels. Ultra’s low-cost, low-decline and predictable operations resulted in free cash flow generation of approximately $56 million for the fourth quarter, allowing us to continue to reduce indebtedness on the trajectory we have forecast,” said Brad Johnson, President and Chief Executive Officer of Ultra.

Fourth Quarter 2019 Financial Results

Ultra’s reported net loss for the quarter ended December 31, 2019 was $1.3 million, or $0.01 per diluted share. The Company reported adjusted net income (1) of $22.6 million, or $0.11 per diluted share, for the quarter ended December 31, 2019. Net income was $39.7 million or $0.20 per diluted share in the quarter ended 2018, with adjusted net income for the same period at $27.4 million or $0.14 per diluted share.

During the fourth quarter of 2019, total revenues excluding hedging settlements were $170.9 million as compared to $273.2 million during the fourth quarter of 2018.  Derivative settlements during these periods were a loss of $2.2 million and of $82.4 million, respectively. The Company’s production of natural gas and oil was 55.4 Bcfe, a decrease from 64.3 Bcfe in the same period of 2018. The decrease in production was based on the Company’s decision to reduce and then suspend drilling in the third quarter of 2019 in response to weak commodity pricing. This decision allowed the Company to generate cash flow from operating activities of $19.8 million and free cash flow of $56.4 million in the fourth quarter of 2019. The Company reported Adjusted EBITDA(5) of $100.6 million for the quarter ended December 31, 2019 compared to $110.8 million for the fourth quarter of 2018. Ultra’s fourth quarter production was comprised of 53.1 billion cubic feet (“Bcf”) of natural gas and approximately 378,000 barrels (“Bbls”) of oil.

During the fourth quarter of 2019, Ultra’s average realized natural gas price was $2.72 per thousand cubic feet (“Mcf”), which included derivative settlements, as compared to $2.58 per Mcf in the fourth quarter of 2018.  Excluding the derivative settlements, the Company’s average price for natural gas was $2.78 per Mcf in the fourth quarter of 2019, compared to $3.95 per Mcf for the fourth quarter of 2018.  Rockies natural gas basis, measured by first-of month Inside FERC Northwest Rockies (“NWROX”) compared to Henry Hub, was positive in the fourth quarter of 2019 by $0.27 per MMBtu.  The Company’s average realized oil price was $60.53 per Bbl, including derivative settlements, for the quarter ended December 31, 2019, as compared to $61.74 per Bbl for the same period in 2018.

Full-Year 2019 Results

Ultra’s reported net income for the year ended December 31, 2019, was $108.0 million, or $0.55 per diluted share as compared with net income of $85.2 million or $0.43 per diluted share for the same period in 2018. Adjusted net income for the year ended December 31, 2019, was $69.1 million, or $0.35 per diluted share, as compared to $149.7 million and $0.76 per diluted share in 2018.

During the year ended December 31, 2019, revenues from natural gas and oil sales, including processing credits, was $742.0 million as compared to $892.5 million in the year ended December 31, 2018. During the year ended December 31, 2019, production of natural gas and oil was 240.2 Bcfe, which was comprised of 230.1 Bcf of natural gas and 1.7 million barrels of oil.

During the year ended December 31, 2019, Ultra’s average realized natural gas price was $2.50 per Mcf, including derivative settlements. Excluding the derivative settlements, the Company’s average price for natural gas was $2.77 per Mcf for both 2019 and 2018, with volatility through each period.  The net basis differential between NWROX and Henry Hub, using first of month pricing was negative $0.04 per MMBtu for the full year 2019 as compared to negative $0.46 in 2018.  The Company’s average realized oil price, including derivative settlements, was $59.97 per Bbl for the year ended December 31, 2019, as compared to $59.44 per Bbl for the same period in 2018.

For the full year 2019, total capital expenditures were $241.1 million. During this period, the Company participated in 94 gross (78.5 net) wells that were turned to sales, including operated and non-operated wells in the Pinedale field in Wyoming. 

Proved Reserves as of December 31, 2019

Year-end 2019 proved reserves were 1,990 Bcfe, consisting entirely of Proved Developed Producing (“PDP”) reserves. Given the decision to suspend the drilling program in the third quarter, citing a need for higher natural gas prices in order to justify capital development, the Company had revisions that transferred out all 570 Bcfe of its Proved Undeveloped (“PUD”) reserves as of December 31, 2019.  For the 20th consecutive year, Netherland, Sewell & Associates, Inc. (“NSAI”), prepared a full reserve report for the Company.  The highlights below summarize the year-end 2019 reserve results:

  • Year-end 2019 proved reserves were 1,990 Bcfe, all of which are in the PDP category, and by volume are comprised of 96 percent natural gas and 4 percent oil,
  • The year-end 2019 PV10 valuation for proved reserves using pre-tax estimated future net cash flows was $1.7 billion(9), and
  • The PV10 valuation of Ultra’s year-end reserves was calculated based on reference prices for natural gas of $2.58 per MMBtu and oil of $55.85 per Bbl in accordance with the rules of the Securities and Exchange Commission (“SEC”).  Applying regional market differentials along with appropriate adjustments for quality, our marketing contracts, energy content, transportation charges, and adjustments for basis over same historical 12-month period, the average prices for the Company’s proved reserves were $2.44 per Mcf for natural gas and $55.36 per Bbl for oil, computed in accordance with the rules of the SEC.

Going Concern Qualification

The report of the Company’s independent registered public accounting firm that accompanies its audited, consolidated financial statements in our Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The failure to deliver audited, consolidated financial statements without a going concern or like qualification or explanation results in a default under each of the Credit Agreement and Term Loan Agreement as of April 14, 2020. We expect that we will be precluded from making additional draws on the Credit Agreement unless a waiver is obtained. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement and the Term Loan Agreement before the expiration of a 30-day grace period, an event of default under each of the Credit Agreement and Term Loan Agreement would occur, which would allow the lenders to accelerate the loans outstanding under the Credit Agreement and Term Loan Agreement. At this time, we do not expect to obtain a waiver of this requirement and we do not currently have sufficient liquidity to repay such indebtedness were it to be accelerated.

Liability Management Update

In February and March 2020, the Company entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors.  The Company previously engaged with certain debtholders regarding a potential out-of-court restructuring, but as previously disclosed on March 5, 2020, such negotiations are no longer occurring.  Negotiations and discussions with certain other debtholders and their advisors are now ongoing regarding a potential in-court restructuring, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions relating to the Company’s indebtedness. 

There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be.  If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings.  We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring.  We discuss these matters in further detail under, among other places, in Note 1 to our consolidated financial statements included in our Annual Report on Form 10-K.

Proved Reserves as of March 31, 2020

In order to fulfill its obligation to evaluate the full cost ceiling and to calculate DD&A of its oil and gas properties, the Company is required to estimate its oil and gas reserves on a quarterly basis.  The estimated proven oil and gas reserves considers the estimated future production based on the most current well information available including decline rate changes causing downward revisions, and updated pricing in accordance with SEC requirements.  These SEC reference prices, together with basis differentials expanding modestly since year end, decreased by 15% for natural gas and <1% for oil, as compared to the pricing utilized as of December 31, 2019.  NSAI prepared a full reserve report of estimated proved reserves as of March 31, 2020 for the Company. The highlights below summarize the March 31, 2020 reserve results:              

  • Consistent with year end, the SEC reference prices utilized in the preparation of the reserves as of March 31, 2020 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period April 2019 through March 2020, which were $2.30 per MMBtu for Henry Hub spot and $55.96 per Bbl for WTI.  Applying regional market differentials along with appropriate adjustments for quality, our marketing contracts, energy content, transportation charges, and updates to basis for the same period, the average prices for the Company’s proved reserves were $2.07 per Mcf for natural gas and $55.35 per Bbl for oil, computed in accordance with the rules of the SEC. 
  • March 31, 2020 proved reserves were 1,766 Bcfe, all of which are in the PDP category, and by volume are comprised of 96 percent natural gas and 4 percent oil,
  • The discounted future net cash flows before income tax estimated at March 31, 2020 was $1.217(10) billion, respectively.             

2020 Capital Budget and Production Forecast

As previously announced, the Company’s capital investment program is expected to be approximately $10 - $20 million for 2020, reflecting Ultra’s decision to suspend drilling and focus on free cash flow generation.  Additionally, the Company is confirming its 2020 production guidance of 182 to 192 Bcfe. In the first quarter, the average daily production rate was 554 MMcfe/d.

Cost Guidance

The following table presents the Company's expected per unit of production expenses for the first quarter and full year 2020.  Production tax guidance assumes forward NYMEX prices for the remainder of the year and realized prices for the periods reported to date.  The Company has previously disclosed that the unit costs are expected to increase as compared to 2019 based on a combination of PDP-only production profile and the reduction of certain costs being capitalized toward its now-suspended development drilling program. The Company has incorporated cost savings into its 2020 guidance of approximately 16 percent for G&A items and approximately 3 percent for LOE items on a gross basis.  The net effect, after the impact of reduced capitalization to the full cost pool in 2020 and the reduced production profile, is as reflected below.  Additionally, the Company renegotiated certain midstream and marketing agreements in the fourth quarter of 2019.  The effect of these renegotiated agreements removes a processing credit previously applied to net gathering expenses and provides for an incremental uplift in realized gas prices.  The net effect is an increase to cash margin by $0.03 - $0.04 per MMBtu. 

2020 Expenses (per Mcfe)  1Q20 Guidance  Full-Year 2020 Guidance 
     
Lease Operating Expense  $0.34 – 0.39  $0.36 – 0.42 
Facility Lease Expense  $0.10 – 0.13  $0.11 – 0.14 
Production Taxes  $0.25 – 0.31  $0.19 – 0.25 
Gathering Fees, gross  $0.32 – 0.36  $0.32 – 0.36 
Gathering Fees, net  $0.31 – 0.35  $0.31 – 0.35 
Transportation Charges  $0.06 – 0.10  $0.04 – 0.08 
Cash G&A  $0.14 – 0.19  $0.15 – 0.20 
DD&A  $0.82 – 0.88  $0.72 – 0.78 
Cash Interest Expense  $0.65 – 0.70  $0.69 – 0.74 
     

Hedging Activity

The Company will continue to evaluate hedging opportunities in order to provide a degree of certainty of cash flows along with being opportunistic in a strengthening natural gas and Rockies basis market.  Management also works to balance the ability to provide upside exposure for the Company as the increase in future commodity prices has a meaningful impact on our cash flows on unhedged volumes given our low operating costs.  The Company remains complaint with its hedging requirements under the terms of its revolving credit facility.  As previously disclosed, these hedging requirements phased out completely as of April 2020.

The table below provides a summary of the hedges in place for the first quarter and as of March 31, 2020:

    Q1 2020        Q2 2020      Q3 2020      Q4 2020      Q1 2021 
Natural Gas Swaps:                             
Volume (MMBtu/d)    260,220        —      —      —      — 
NYMEX ($/MMBtu)  2.76      —    —    —    — 
                             
Natural Gas Collars:                             
Volume (MMBtu/d)    36,374        236,000      175,000      215,000      80,000 
NYMEX Floor ($/MMBtu)  2.76      2.32    2.41    2.44    2.46 
NYMEX Ceiling ($/MMBtu)  3.19      2.83    2.85    2.92    3.05 
                             
Natural Gas Puts:                             
Volume (MMBtu/d)    —        35,593      80,000      30,000      — 
NYMEX Strike Price ($/MMBtu)  —      2.28    2.29    2.26    — 
                             
Oil Swaps:                             
Volume (Bbl/d)    2,750        1,700      1,000      —      — 
NYMEX ($/Bbl)  60.38      59.66    60.00    —    — 
                             
Natural Gas Basis Swap Contracts:                             
NW Rockies Volume (MMBtu/d)(a)    328,187        —      —      —      — 
Price Differential ($/MMBtu)  (0.06    —    —    —    — 

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

Continued Exemptive Relief from Canada's National Instrument 51-101

Ultra is pleased to announce that applicable provincial securities commissions in Canada have issued a decision document (the "Decision") which has the effect of granting Ultra continued exemptive relief from the disclosure requirements contained in Canada's National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") in addition to other continuous disclosure obligations under applicable Canadian securities laws.  Ultra had obtained similar exemptive relief in 2005 but was required to obtain this new Decision as a result of the facts underlying the original exemptive relief changing due to the delisting of Ultra's common stock from the NYSE and Nasdaq.

As a result of the Decision, and provided that certain conditions set out in the Decision are met on an on-going basis, Ultra will not be required to comply with the Canadian requirements of NI 51-101 and, accordingly, will not be required to file Form 51-101F1 Statement of Reserves Data and Other Oil and Gas Information, Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor or Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure. In lieu of such filings, the Decision permits Ultra to provide disclosure in respect of its oil and gas activities in the form permitted by, and in accordance with, the legal requirements of the  United States Securities Act of 1933, the United States Securities Exchange Act of 1934 and the rules and regulations of the SEC and the rules and obligations of any exchange upon which Ultra's common stock is listed (collectively, "U.S. Rules").  The Decision also provides that Ultra is required to file all such oil and gas disclosure and other continuous disclosure with the appropriate Canadian securities commissions on sedar.com as soon as practicable after such disclosure is filed with the SEC.

Ultra's disclosure relating to its oil and gas activities therefore continue to comply with the U.S. Rules rather than NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. The U.S. Rules differ in a number of respects from the disclosure otherwise required under Canada's NI 51-101 and the Canadian Oil and Gas Evaluation Handbook and investors are urged to consider these differences when considering all future disclosures made by Ultra relating to its oil and gas activities.

 
Ultra Petroleum Corp. 
Selected Operating and Financial Data 
As of and for the Years and Quarters Ended December 31, 2019 and 2018 
All amounts 
 
  For the Year Ended      For the Quarter Ended   
  December 31,      December 31,   
  2019      2018      2019      2018   
Volumes:                               
Natural gas (Mcf)    230,121        260,406        53,098        61,489   
Oil and condensate (Bbls)    1,683        2,442        378        473   
Mcfe - Total    240,219        275,058        55,366        64,327   
                               
Revenues:                               
Natural gas sales  637,007      722,313      147,586      242,609   
Oil sales    97,231        153,534        22,000        27,560   
Other revenue    7,794        16,652        1,343        3,041   
Total operating revenues    742,032        892,499        170,929        273,210   
                               
Expenses:                               
Lease operating expenses    70,608        90,290        19,581        19,064   
Facility lease expense    25,468        25,947        5,640        6,390   
Production taxes    79,459        93,322        18,114        30,699   
Gathering fees    78,261        89,294        18,427        20,684   
Transportation charges    1,496        512        1,303        76   
Total lease operating costs    255,292        299,365        63,065        76,913   
                               
Depletion and depreciation    204,227        204,255        47,224        52,301   
General and administrative    26,551        25,005        5,473        8,771   
Other operating expenses, net    28,889        9,118        2,269        7,519   
Total operating expenses    514,959        537,743        118,031        145,504   
                               
Other (expense) income, net    392        1,212        88        18   
Contract settlement income (expense), net    13,468        12,656        —        15,331   
Interest expense    (129,398      (148,316      (31,322      (36,382 
Deferred gain on sale of liquids gathering system    —        10,553        —        2,638   
Realized gain (loss) on commodity derivatives    (58,879      (85,413      (2,176      (82,364 
Unrealized gain (loss) on commodity derivatives    54,282        (59,799      (21,674      12,758   
Total other (expense) income, net    (120,135      (269,107      (55,084      (88,001 
                               
Income before income taxes    106,938        85,649        (2,186      39,705   
Income tax provision (benefit)    (1,050      442        (881      —   
                               
Net income  107,988      85,207      (1,305    39,705   
                               
Adjusted Net Income Reconciliation:                               
Net income  107,988      85,207      (1,305    39,705   
Contract settlement income (expense), net    (13,468      (12,656      —        (15,331 
Debt exchange expenses    —        8,272        —        8,272   
Unrealized (gain) loss on commodity derivatives    (54,282      59,799        21,674        (12,758 
Other operating expenses, net    28,889        9,118        2,269        7,519   
Adjusted net income (1)  69,127      149,740      22,638      27,407   
                               
Net cash provided by operating activities  302,416      310,897      19,815      1,392   
Operating cash flow (2)  288,786      346,994      73,855      69,075   
(see non-GAAP reconciliation)                               
                               
Adjusted EBITDA (5)  404,273      504,024      100,603      110,766   
(see non-GAAP reconciliation)                               
                               
Weighted average shares (000's) (9)                               
Basic    197,651        196,964        197,858        197,190   
Diluted    197,690        197,541        197,906        197,617   
                               
Earnings (loss) per share                               
Net income (loss) - basic  0.55      0.43      (0.01    0.20   
Net income (loss)- diluted  0.55      0.43      (0.01    0.20   
                               
Adjusted earnings per share (1)                               
Adjusted net income - basic  0.35      0.76      0.11      0.14   
Adjusted net income - diluted  0.35      0.76      0.11      0.14   
                               
Realized Prices                               
Natural gas ($/Mcf), excluding realized gain on commodity
  derivatives 
2.77      2.77      2.78      3.95   
Natural gas ($/Mcf), including realized gain on commodity
  derivatives 
2.50      2.48      2.72      2.58   
Oil liquids ($/Bbl), excluding realized gain on commodity
  derivatives 
57.78      62.88      58.20      58.27   
Oil liquids ($/Bbl), including realized gain on commodity
  derivatives 
59.97      59.44      60.53      61.74   
                               
Costs Per Mcfe                               
Lease operating expenses  0.29      0.33      0.35      0.30   
Facility lease expense  0.11      0.09      0.10      0.10   
Production taxes  0.33      0.34      0.33      0.48   
Gathering fees (net)  0.29      0.27      0.31      0.28   
Transportation charges  0.01      —      0.03      —   
Depletion and depreciation  0.85      0.74      0.85      0.81   
General and administrative - total  0.11      0.09      0.10      0.14   
Interest expense, including PIK and the amortization of deferred financing costs and the premium  0.54      0.54      0.57      0.57   
  2.53      2.40      2.64      2.68   
Adjusted Margins                               
Adjusted Net Income Margin (3)    10      19      14      14 
Adjusted Operating Cash Flow Margin (4)(7)    42      43      44      36 
Adjusted EBITDA Margin (6)    59      63      60      58 
                               
 
  As of   
  December 31,      December 31,   
  2019      2018   
               
Cash and cash equivalents  1,664      17,014   
Outstanding debt               
Credit Agreement    64,700        104,000   
Term Loan, secured due 2024    968,756        975,000   
Second Lien Notes, secured, due 2024    583,853        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  1,992,748      2,044,035   
Add: Premium on exchange transaction    203,883        228,096   
Less: Deferred financing costs    (46,421      (56,650 
Total outstanding debt, net  2,150,210      2,215,481   
               
           
  For the Year Ended      For the Quarter Ended   
  December 31,      December 31,   
  2019      2018      2019      2018   
Net cash provided by operating activities  302,416      310,897      19,815      1,392   
Net changes in operating assets and liabilities and other
  non-cash or non-recurring items (7) 
  (13,630      36,097        52,737        67,683   
Operating Cash Flow (2)  288,786      346,994      72,552      69,075   
                               
           
  For the Year Ended      For the Quarter Ended   
  December 31,      December 31,   
  2019      2018      2019      2018   
Net income  107,988      85,207      (1,305    39,705   
Interest expense    129,398        148,316        31,322        36,382   
Depletion and depreciation    204,227        204,255        47,224        52,301   
Contract settlement (income) expense, net    (13,468      (12,656      —        (15,331 
Unrealized (gain) loss on commodity derivatives    (54,282      59,799        21,674        (12,758 
Deferred gain on sale of liquids gathering system    —        (10,553      —        (2,638 
Stock compensation expense    2,571        11,824        300        278   
Taxes    (1,050      442        (881      —   
Debt exchange expenses    —        8,272        —        8,272   
Other operating expenses, net    28,889        9,118        2,269        4,555   
Adjusted EBITDA (5)  404,273      504,024      100,603      110,766   
Capital and PP&E expenditures, net of proceeds received    (241,636      (374,387      (8,058      (90,312 
Cash interest expense    (145,339      (137,812      (36,146      (34,211 
Free cash flow (8)  17,298      (8,175    56,399      (13,757 
                               
Production (Mcfe)    240,219        275,058        55,366        64,327   
Adjusted EBITDA per Mcfe  1.68      1.83      1.82      1.72 
Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd