April 25, 2019 - 6:30 AM EDT
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EQT Reports First Quarter 2019 Results

PITTSBURGH

New management team delivers strong operational improvements and significant free cash flow generation in consecutive quarters

EQT Corporation (NYSE: EQT) today announced financial and operational performance results for the first quarter 2019.

First Quarter Highlights:

  • Sales volumes of 383 Bcfe exceeded guidance of 360-380 Bcfe and increased 13%, adjusted for divestitures, from the first quarter 2018
  • Full year sales volume guidance raised 10 Bcfe to 1,480 - 1,520 Bcfe while full year capital expenditure guidance remains unchanged at $1.85 - $1.95 billion
  • Diluted earnings per share (EPS) and adjusted EPS* increased 113% and 24% to $0.75 and $0.83, respectively, despite a 5% lower average realized price compared to the first quarter of 2018
  • Income from continuing operations and adjusted EBITDA* increased 112% and 2% over the first quarter 2018 to $191 million and $710 million, respectively
  • Capital expenditures decreased 22% to $476 million while feet of pay turned-in-line increased compared to the first quarter 2018
  • Net cash provided by operating activities was $871 million in the first quarter 2019 and $1.4 billion in the last two quarters; adjusted free cash flow* was $171 million in the first quarter 2019 and $306 million in the last two quarters
  • Positive operational results included significant improvements in rig and frac crew efficiencies such as:
    • Drilling days per 1,000 feet improved 25% over prior quarter and 32% since November 2018
    • Frac stages per crew increased 30% and non-productive time decreased 70% over the first quarter 2018
  • Cash operating expenses per unit decreased 5% over the first quarter 2018
  • On-target to achieve $150 million of cost savings in 2019, including $50 million identified as part of the Target 10% Initiative
  • Net debt decreased by approximately $500 million since December 31, 2018

*A non-GAAP measure. Please see the Non-GAAP Disclosures section of this news release for important disclosures.

Robert J. McNally, president and chief executive officer, said, “Our strong operational performance is demonstrated through our first quarter results. We are achieving the ambitious targets we set in January, as evidenced by our improved financial and operational metrics in the quarter. We have generated over $300 million in adjusted free cash flow over the last two quarters and remain on track to achieve our 2019 free cash flow target.”

McNally added, “We will continue to identify incremental opportunities to operate more efficiently and further reduce costs. EQT is uniquely positioned to be one of the lowest-cost and most efficient operators in the Marcellus basin. Our consolidated core acreage position and long-lived inventory will enable us to increase lateral lengths and spacing, drive down per unit operating and capital costs, and deliver substantial free cash flow for many years to come. With a world-class asset base, a clear and compelling strategic plan, and an experienced, restructured leadership team focused on operational efficiency, we are building on our progress and creating significant long-term value for all EQT shareholders.”

           

FIRST QUARTER 2019 FINANCIAL AND OPERATIONAL PERFORMANCE

 
Three Months Ended
March 31,
%
($ millions, except EPS) 2019     2018 Change Change
Total sales volume (Bcfe) 383 357 26 7 %
Income (loss) from continuing operations $ 191 $ (1,579 ) $ 1,770 112 %
Adjusted net income from continuing operations (a non-GAAP measure) $ 212 $ 179 $ 33 18 %
Adjusted EBITDA from continuing operations (a non-GAAP measure) $ 710 $ 695 $ 15 2 %
Diluted earnings per share (EPS) from continuing operations $ 0.75 $ (5.96 ) $ 6.71 113 %
Adjusted EPS from continuing operations (a non-GAAP measure) $ 0.83 $ 0.67 $ 0.16 24 %
Net cash provided by operating activities $ 871 $ 904 $ (33 ) (4 )%
Adjusted free cash flow (a non-GAAP measure) $ 171 $ 89 $ 82 92 %
 

In the first quarter 2019, the Company reported income from continuing operations of $191 million, or $0.75 per diluted share, compared to a loss from continuing operations of $1.6 billion, or a loss of $5.96 per diluted share, for the first quarter 2018. The increase was primarily attributable to an impairment charge recorded in the first quarter 2018. Adjusted net income from continuing operations, which excludes impairment charges, non-cash derivatives and other items impacting comparability between periods, was $33 million higher than the same quarter last year.

Sales of natural gas, oil and natural gas liquids (NGLs) increased $45 million as a result of a 7% increase in sales volumes in 2019, which was more than offset by a loss on derivatives not designated as hedges in 2019. Adjusted for volumes from the divestitures of the Company's Huron and Permian assets in 2018, sales volumes increased 13% in the first quarter 2019.

Compared to the same quarter last year, average realized price was 5% lower at $3.16 per Mcfe, primarily on a lower average natural gas differential as a result of lower gas daily prices during the first quarter 2019 at sales points off the Company's Northeast capacity. Lower gas daily pricing also negatively impacted the Company's first quarter average natural gas differential compared to guidance; however, the Company reiterates its full-year 2019 average differential guidance.

Net cash provided by operating activities decreased by 4% and adjusted free cash flow increased 92%. Adjusted free cash flow in the first quarter 2019 was $171 million, unadjusted for an $8 million litigation reserve and $4 million of proxy and transaction costs.

The Non-GAAP Disclosures section of this news release provides reconciliations of non-GAAP financial measures to the most comparable GAAP financial measures, as well as important disclosures regarding certain projected non-GAAP financial measures.

   

Capital Expenditures

 
Three Months Ended
March 31,
(millions) 2019     2018
Reserve development $ 401 $ 490
Land and lease 45 60
Capitalized overhead 17 29
Capitalized interest 7 7
Other production infrastructure 6 10
Property acquisitions 14
Other corporate items  
Total capital expenditures from continuing operations $ 476 $ 610
 
   

Operating Expenses Per Unit
The following presents certain of the Company's operating expenses on a per unit basis.

 
Three Months Ended
March 31,
($/Mcfe) 2019     2018
Gathering $ 0.56 $ 0.54
Transmission 0.50 0.50
Processing 0.08 0.13
LOE, excluding production taxes 0.06 0.10
Production taxes 0.05 0.07
Exploration
SG&A 0.13   0.11
Total cash operating expenses per unit $ 1.38 $ 1.45
 
Production depletion $ 1.01 $ 1.07
 

Per unit cash operating expenses decreased 5%, primarily as a result of increased sales volume. On a per unit basis, processing expense was $0.05 per Mcfe lower, lease operating expense (LOE) was $0.04 per Mcfe lower and production taxes were $0.02 per Mcfe lower, each of which were favorably impacted by the divestitures of the Company's Huron and Permian assets in 2018. Excluding the sales volumes related to the divestitures of the Huron and Permian assets in 2018, gathering expense per unit was $0.57 per Mcfe in 2018. When adjusting for the impact of an $8 million litigation reserve recorded during the first quarter 2019, selling, general and administrative expense (SG&A) was $0.11 per Mcfe.

Liquidity

As of March 31, 2019, the Company had $350 million of credit facility borrowings and no letters of credit outstanding under its $2.5 billion credit facility. As of March 31, 2019, net debt was lower by approximately $500 million compared to December 31, 2018 as a result of working capital dynamics and positive adjusted free cash flow over the past two quarters. Adjusted operating cash flow is forecasted to be $2.2 to $2.3 billion in 2019, which fully funds the Company's capital expenditure plan of $1.85 to $1.95 billion and is expected to deliver $300 to $400 million of adjusted free cash flow.

Operational Update

The Company’s strong first quarter 2019 operational performance reflects the move to stable operations and the Company’s focus on enhanced operational efficiencies. During the quarter, the Company drilled 17 wells with total curve and lateral footage of greater than 14,000 feet in one-run, and surpassed the mile-per-day rate of penetration mark on 4 wells. The team also set a basin bit record for the longest one run at 19,426 feet. Horizontal drilling performance improved 32% when compared to November of 2018 to 0.79 days per 1,000 feet, down from 1.17 days per 1,000 feet.

The Company's completions operation also saw significantly improved results, increasing frac stages per crew by 30% and decreasing non-productive time by 70% year-over-year. The Company's frac plug drill-out operations have also seen significant efficiency gains with a 71% improvement in the average number of plugs per day, reducing cycle times by nearly 3 days per 100 plugs. In April, the Company’s frac plug drill-out operations completed 43 frac plugs and cleaned 7,550 feet in a 24-hour period - positioning the Company as one of the most efficient in the Appalachian basin and setting a Company record.

As part of the Company's ongoing effort to increase operational efficiencies and reduce costs, the Company was also able to successfully negotiate a penalty-free, early reduction to its horizontal rig count that results in approximately 30 fewer horizontal wells being drilled during 2019 compared to the operational plan announced in January. The Company will also spud approximately 15 fewer wells. Additionally, as a result of the operational efficiency gains in completion operations, the Company now expects to frac an additional 10 wells in 2019. Finally, seven fewer wells are expected to be turned-in-line during 2019 as a result of non-operated activity by joint venture partners and timing. These operational changes will not impact full year 2019 volumes or capital expenditures; they represent an acceleration of the Company's optimization of resource count and development cadence that will enhance the Company's capital efficiency as it moves into 2020.

Finally, lateral lengths and well costs were in-line with the Company’s first quarter 2019 expectations and are on-track to achieve full-year guidance targets.

           

WELL STATISTICS

Net Wells Drilled (spud)

 
PA Marcellus WV Marcellus Ohio Utica
Q1 2019 27 2 1
2019 Forecast 83 11 17
Q2 2019 Forecast 18 2 7
 

• Q1 2019 average lateral lengths: PA Marcellus 11,300'; WV Marcellus 8,400'; Ohio Utica 9,600'

• 2019 forecasted average lateral lengths: PA Marcellus 13,200'; WV Marcellus 6,500'; Ohio Utica 11,200'

 
           

Net Wells Turned-in-line (TIL)

 
PA Marcellus WV Marcellus Ohio Utica

Q1 2019*

24 - 5
2019 Forecast* 101 20 19
Q2 2019 Forecast 27 10 2
 

• Q1 2019 average lateral lengths: PA Marcellus 10,800'; Ohio Utica 8,300'

• 2019 forecasted average lateral lengths: PA Marcellus 11,300'; WV Marcellus 6,200'; Ohio Utica 12,200'

*Q1 PA Marcellus includes 6 Upper Devonian wells. Forecasted full-year 2019 PA Marcellus includes 8 Upper Devonian wells.

 
                   

Marcellus Horizontal Gross Well Status (cumulative since inception)*

 

As of
3/31/19

As of
12/31/18

As of
9/30/18

As of
6/30/18

As of
3/31/18

Wells drilled (spud) 1,848 1,819 1,798 1,777 1,749
Wells online 1,589 1,571 1,529 1,468 1,430
Wells complete, not online 33 19 22 40 35
Wells drilled, uncompleted 226 229 247 269 284
 

*These totals may differ from previous presentations to account for purchases, dispositions, wells plugged, or that have had a change in target formation to/from Marcellus.

 
                   

Ohio Utica Horizontal Gross Well Status*

 

As of
3/31/19

As of
12/31/18

As of
9/30/18

As of
6/30/18

As of
3/31/18

Wells drilled (spud) 255 251 251 246 236
Wells online 229 221 218 198 196
Wells complete, not online 2 8 1 14 2
Wells drilled, uncompleted 24 22 32 34 38
 

*These totals may differ from previous presentations to account for acquisitions, dispositions, or wells plugged.

 
                   

HEDGING (as of April 22, 2019)

The Company’s total natural gas production NYMEX hedge positions through 2023 are:

 
2019 (a) 2020 2021 2022 2023
Swaps
Volume (MMDth) 591 553 306 136 61
Average Price($/Dth) $ 2.91 $ 2.82 $ 2.78 $ 2.75 $ 2.74
Calls - Net Short
Volume (MMDth) 261 187 37 22 7
Average Short Strike Price ($/Dth) $ 3.11 $ 3.15 $ 3.25 $ 3.20 $ 3.18
Puts - Net (Short) Long
Volume (MMDth) (36 ) 10
Average Long Strike Price ($/Dth) $ 2.97 $ $ 2.71 $ $
Fixed Price Sales (b)
Volume (MMDth) 59 12 3
Average Price ($/Dth) $ 2.83 $ 2.77 $ 2.77 $ $
 
      (a)   April 1 - December 31, 2019.
(b) The difference between the fixed price and NYMEX are included in average differential on the Company’s price reconciliation.
 

First Quarter 2019 Conference Call Webcast Information

The Company's conference call with securities analysts begins at 10:30 a.m. ET today and will be broadcast live via the Company's web site at www.eqt.com, and on the investor information page of the Company’s web site at ir.eqt.com, with a replay available for seven days following the call.

2019 GUIDANCE

See the Non-GAAP Disclosures section for important information regarding the non-GAAP financial measures included in this news release, including reasons why the Company is unable to provide a projection of its 2019 net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP, to projected adjusted operating cash flow and adjusted free cash flow, or a projection of its 2019 net income, the most comparable financial measure calculated in accordance with GAAP, to projected adjusted EBITDA.

               
Production         Q2 2019         Full-Year 2019
Total sales volume (Bcfe) 355 - 375 1,480 - 1,520
Liquids sales volume, excluding ethane (Mbbls) 2,015 - 2,115 8,350 - 8,550
Ethane sales volume (Mbbls) 1,110 - 1,210 4,470 - 4,670
Total liquids sales volume (Mbbls) 3,125 - 3,325 12,820 - 13,220
                     
Resource Counts                    
Marcellus / Utica Rigs 6 - 8
Top-hole Rigs 2 - 4
Frac Crews 5 - 7
                     
Unit Costs ($ / Mcfe)                    
Gathering $0.54 - 0.56
Transmission $0.49 - 0.51
Processing $0.08 - 0.10
LOE, excluding production taxes $0.05 - 0.07
Production taxes $0.04 - 0.06
SG&A $0.11 - 0.13
 
Average differential ($ / Mcf) $(0.55) - $(0.35) $(0.45) - (0.25)
                     
($'s in Billions)                    
Adjusted EBITDA (a non-GAAP measure) $2.3 - 2.4
Adjusted operating cash flow (a non-GAAP measure) $2.2 - 2.3
Capital expenditures $1.85 - 1.95
Adjusted free cash flow (a non-GAAP measure) $0.3 - 0.4
 

Based on average NYMEX natural gas price (April to December) of $2.79 per MMbtu as of March 31, 2019.

 

NON-GAAP DISCLOSURES

Adjusted Net Income from Continuing Operations and Adjusted Earnings per Diluted Share (Adjusted EPS) from Continuing Operations

Adjusted net income from continuing operations and adjusted EPS from continuing operations are non-GAAP supplemental financial measures that are presented because they are important measures used by the Company's management to evaluate period-to-period comparisons of earnings trends. Adjusted net income from continuing operations and adjusted EPS from continuing operations should not be considered as alternatives to income (loss) from continuing operations or diluted EPS from continuing operations presented in accordance with GAAP. Adjusted net income from continuing operations as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement, impairment/loss on the sale of long-lived assets, lease impairments and expirations, proxy and transaction costs and certain other items that impact comparability between periods. Management utilizes adjusted net income from continuing operations to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts; thus, the income from natural gas sales is not impacted by the often-volatile fluctuations in the fair value of derivatives prior to settlement. The measure also excludes other items that affect the comparability of results or that are not indicative of trends in the ongoing business. Management believes that adjusted net income from continuing operations as presented provides useful information for investors for evaluating period-over-period earnings.

The table below reconciles adjusted net income from continuing operations and adjusted EPS from continuing operations with income (loss) from continuing operations and diluted EPS from continuing operations, the most comparable financial measures calculated in accordance with GAAP, each as derived from the Statements of Condensed Consolidated Operations to be included in the Company's report on Form 10-Q for the quarter ended March 31, 2019.

   
Three Months Ended
March 31,
2019     2018
(Thousands, except per share information)
Income (loss) from continuing operations $ 190,691 $ (1,578,533 )
Add back / (deduct):
Impairment/loss on sale of long-lived assets 2,329,045
Lease impairments and expirations 29,534 3,879
Proxy and transaction costs 4,089 10,078
Loss (gain) on derivatives not designated as hedges 131,996 (62,592 )
Net cash settlements paid on derivatives not designated as hedges (63,634 ) (38,629 )
Premiums received for derivatives that settled during the period 2,437 234
Increase in litigation reserves 8,000
Unrealized gain on investment in Equitrans Midstream Corporation (89,055 )
Tax impact of non-GAAP items (a) (2,185 ) (484,930 )
Adjusted net income from continuing operations $ 211,873   $ 178,552  
Diluted weighted average common shares outstanding 255,387 265,169
Diluted EPS from continuing operations $ 0.75 $ (5.96 )
Adjusted EPS from continuing operations $ 0.83 $ 0.67
 
        (a)   The tax impact of non-GAAP items represents the incremental tax expense that would have been incurred had these items been excluded from income (loss) from continuing operations, which resulted in blended tax rates of 9.4% and 21.6% for the three months ended March 31, 2019 and 2018, respectively. These rates differ from the Company's statutory tax rate primarily due to the impact of items specific to each respective quarter.
 

Adjusted Operating Cash Flow and Adjusted Free Cash Flow

Adjusted operating cash flow is defined as the Company’s net cash provided by operating activities less changes in other assets and liabilities, less EBITDA attributable to discontinued operations (a non-GAAP supplemental financial measure defined below), plus interest expense attributable to discontinued operations and cash distributions from discontinued operations. Adjusted free cash flow is defined as adjusted operating cash flow less accrual-based capital expenditures attributable to continuing operations. Adjusted operating cash flow and adjusted free cash flow are non-GAAP supplemental financial measures that the Company's management and external users of its consolidated financial statements, such as industry analysts, lenders and ratings agencies use to assess the Company’s liquidity. The Company believes that adjusted operating cash flow and adjusted free cash flow provide useful information to management and investors in assessing the impact of the Company’s ability to generate cash flow in excess of capital requirements and return cash to shareholders. Adjusted operating cash flow and adjusted free cash flow should not be considered as alternatives to net cash provided by operating activities or any other measure of liquidity presented in accordance with GAAP.

The table below reconciles adjusted operating cash flow and adjusted free cash flow with net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Condensed Consolidated Cash Flows to be included in the Company's report on Form 10-Q for the quarter ended March 31, 2019.

   
Three Months Ended
March 31,
2019     2018
(Thousands)
Net cash provided by operating activities $ 871,287 $ 904,412
(Deduct) / add back changes in other assets and liabilities (223,934 ) 240  
Operating cash flow $ 647,353 $ 904,652
(Deduct) / add back:
EBITDA attributable to discontinued operations (a) (292,117 )
Interest expense attributable to discontinued operations 12,102
Cash distributions from discontinued operations (b)   74,967  
Adjusted operating cash flow $ 647,353 $ 699,604
(Deduct):
Capital expenditures attributable to continuing operations (476,022 ) (610,139 )
Adjusted free cash flow $ 171,331   $ 89,465  
 
        (a)   As a result of the separation of the Company's midstream business from its upstream business and subsequent spin-off of Equitrans Midstream Corporation (Equitrans Midstream) in November 2018, the results of operations of Equitrans Midstream are presented as discontinued operations in the Company's Statements of Condensed Consolidated Operations. EBITDA attributable to discontinued operations is a non-GAAP supplemental financial measure reconciled in the section below.
(b) Cash distributions from discontinued operations represents the cash distributions payable from EQM Midstream Partners, LP, EQGP Holdings, LP and Rice Midstream Partners LP (the Company's former midstream affiliates) to the Company for the three months ended March 31, 2018.
 

The table below reconciles adjusted operating cash flow and adjusted free cash flow with net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Condensed Consolidated Cash Flows to be included in the Company's report on Form 10-Q for the quarter ended March 31, 2019 and for the three months ended December 31, 2018.

           
Three Months Ended
March 31, 2019
Three Months Ended

December 31, 2018

Total
(Thousands)
Net cash provided by operating activities $ 871,287 $ 530,866 $ 1,402,153
(Deduct) / add back changes in other assets and liabilities (223,934 ) 261,216   37,282  
Operating cash flow $ 647,353 $ 792,082 $ 1,439,435
(Deduct) / add back:
EBITDA attributable to discontinued operations (a) (118,934 ) (118,934 )
Interest expense attributable to discontinued operations   19,452   19,452  
Adjusted operating cash flow $ 647,353 $ 692,600 $ 1,339,953
(Deduct):
Capital expenditures attributable to continuing operations (476,022 ) (558,351 ) (1,034,373 )
Adjusted free cash flow $ 171,331   $ 134,249   $ 305,580  
 
        (a)   As a result of the separation of the Company's midstream business from its upstream business and subsequent spin-off of Equitrans Midstream in November 2018, the results of operations of Equitrans Midstream are presented as discontinued operations in the Company's Statements of Condensed Consolidated Operations. EBITDA attributable to discontinued operations is a non-GAAP supplemental financial measure reconciled in the section below.
 

The Company has not provided projected net cash provided by operating activities or reconciliations of projected adjusted operating cash flow and adjusted free cash flow to projected net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project net cash provided by operating activities for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts such as predicting the timing of its and customers’ payments, with accuracy to a specific day, months in advance. Furthermore, the Company does not provide guidance with respect to its average realized price, among other items, that impact reconciling items between net cash provided by operating activities and adjusted operating cash flow and adjusted free cash flow, as applicable. Natural gas prices are volatile and out of the Company’s control, and the timing of transactions and the income tax effects of future transactions and other items are difficult to accurately predict. Therefore, the Company is unable to provide projected net cash provided by operating activities, or the related reconciliations of projected adjusted operating cash flow and adjusted free cash flow to projected net cash provided by operating activities, without unreasonable effort.

EBITDA Attributable to Discontinued Operations

EBITDA attributable to discontinued operations is a non-GAAP supplemental financial measure defined as income from discontinued operations, net of tax plus interest expense, income tax expense, depreciation and amortization of intangible assets attributable to discontinued operations for the three months ended March 31, 2018.

The table below reconciles EBITDA attributable to discontinued operations with income from discontinued operations, net of tax, the most comparable financial measure calculated in accordance with GAAP, as reported in the Statements of Condensed Consolidated Operations to be included in the Company’s report on Form 10-Q for the quarter ended March 31, 2019.

   
Three Months Ended
March 31, 2018
(Thousands)
Income from discontinued operations, net of tax $   133,554
Add back / (deduct):
Interest expense 12,102
Income tax expense 90,875
Depreciation 45,200
Amortization of intangible assets 10,386
EBITDA attributable to discontinued operations $   292,117
 

Adjusted Operating Revenue

Adjusted operating revenue (also referred to as total natural gas & liquids sales, including cash settled derivatives) is a non-GAAP supplemental financial measure that is presented because it is an important measure used by the Company’s management to evaluate period-over-period comparisons of earnings trends. Adjusted operating revenue as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and the revenue impact of net marketing services and other revenues. Management utilizes adjusted operating revenue to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus does not impact the revenue from natural gas sales with the often-volatile fluctuations in the fair value of derivatives prior to settlement. Adjusted operating revenue also excludes "net marketing services and other" because management considers this revenue to be unrelated to the revenue for its natural gas and liquids production. "Net marketing services and other" includes both the cost of and recoveries on third-party pipeline capacity not used for the Company's sales volumes as well as revenue for gathering services. Management further believes that adjusted operating revenue, as presented, provides useful information to investors for evaluating period-over-period earnings trends.

The table below reconciles adjusted operating revenue to total operating revenue, the most comparable financial measure calculated in accordance with GAAP, as reported in the Statements of Condensed Consolidated Operations to be included in the Company’s report on Form 10-Q for the quarter ended March 31, 2019.

   
Three Months Ended
March 31,
2019     2018
(Thousands, unless noted)
Total operating revenue $ 1,143,173 $ 1,312,036
Add back / (deduct):
Loss (gain) on derivatives not designated as hedges 131,996 (62,592 )
Net cash settlements paid on derivatives not designated as hedges (63,634 ) (38,629 )
Premiums received for derivatives that settled during the period 2,437 234
Net marketing services and other (3,556 ) (23,070 )
Adjusted operating revenue $ 1,210,416 $ 1,187,979
Total sales volumes (MMcfe) 383,470 357,005
Average realized price ($/Mcfe) $ 3.16 $ 3.33
 

Adjusted EBITDA

Adjusted EBITDA is defined as income (loss) from continuing operations, plus interest expense, income tax expense (benefit), depreciation and depletion, amortization of intangible assets, long-lived asset impairments, lease impairments and expirations, the revenue impact of changes in the fair value of derivative instruments prior to settlement, unrealized (gain) loss on investment in Equitrans Midstream Corporation, proxy and transaction costs and certain other items that impact comparability between periods. Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of the Company’s consolidated financial statements, such as industry analysts, lenders and ratings agencies use to assess the Company’s earnings trends. The Company believes that adjusted EBITDA is an important measure used by the Company’s management and investors in evaluating period-over-period comparisons of earnings trends. Adjusted EBITDA should not be considered as an alternative to the Company’s net income presented in accordance with GAAP. Adjusted EBITDA excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and other items that affect the comparability of results and are not trends in the ongoing business. Management utilizes adjusted EBITDA to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus the income from natural gas is not impacted by the often-volatile fluctuations in fair value of derivatives prior to settlement.

The table below reconciles adjusted EBITDA with income (loss) from continuing operations, the most comparable financial measure as calculated in accordance with GAAP, as reported in the Statements of Condensed Consolidated Operations to be included in the Company’s report on Form 10-Q for the quarter ended March 31, 2019.

   
Three Months Ended
March 31,
2019     2018
(Thousands)
Income (loss) from continuing operations $ 190,691 $ (1,578,533 )
Add back / (deduct):
Interest expense 56,573 57,911
Income tax expense (benefit) 38,234 (429,840 )
Depreciation and depletion 391,113 392,693
Amortization of intangible assets 10,342 10,342
Impairment/loss on sale of long-lived assets 2,329,045
Lease impairments and expirations 29,534 3,879
Proxy and transaction costs 4,089 10,078
Loss (gain) on derivatives not designated as hedges 131,996 (62,592 )
Net cash settlements paid on derivatives not designated as hedges (63,634 ) (38,629 )
Premiums received for derivatives that settled during the period 2,437 234
Increase in litigation reserves 8,000
Unrealized gain on investment in Equitrans Midstream Corporation (89,055 )  
Adjusted EBITDA $ 710,320   $ 694,588  
 

The Company has not provided projected net income or a reconciliation of projected adjusted EBITDA to projected net income, the most comparable financial measure calculated in accordance with GAAP, because the Company does not provide guidance with respect to depletion and depreciation expense, income tax expense, the revenue impact of changes in the projected fair value of derivative instruments prior to settlement or unrealized gains and losses on its investments in equity securities. Therefore, projected net income and a reconciliation of projected adjusted EBITDA to projected net income, are not available without unreasonable effort.

About EQT Corporation:

EQT Corporation is a natural gas production company with emphasis in the Appalachian Basin and operations throughout Pennsylvania, West Virginia and Ohio. With 130 years of experience and a long-standing history of good corporate citizenship, EQT is the largest producer of natural gas in the United States. As a leader in the use of advanced horizontal drilling technology, EQT is committed to minimizing the impact of drilling-related activities and reducing its overall environmental footprint. Through safe and responsible operations, EQT is helping to meet our nation’s demand for clean-burning energy, while continuing to provide a rewarding workplace and support for activities that enrich the communities where its employees live and work. Visit EQT Corporation at www.EQT.com; and to learn more about EQT’s sustainability efforts, please visit https://csr.eqt.com.

EQT Management speaks to investors from time to time and the analyst presentation for these discussions, which is updated periodically, is available via the Company’s investor relationship website at https://ir.eqt.com.

Cautionary Statements

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that a company anticipates as of a given date to be economically and legally producible and deliverable by application of development projects to known accumulations. The Company uses certain terms, such as “EUR” (estimated ultimate recovery) and “3P” (proved, probable and possible), that the SEC’s guidelines prohibit the Company from including in filings with the SEC. These measures are by their nature more speculative than estimates of reserves prepared in accordance with SEC definitions and guidelines and accordingly are less certain.

Total sales volume per day (or daily production) is an operational estimate of the daily production or sales volume on a typical day (excluding curtailments).

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

This news release contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this news release specifically include the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s strategy to develop its reserves; drilling plans and programs (including the number, type, spacing, average length-of-pay or lateral length and location of wells to be drilled or turned-in-line, the number and type of drilling rigs, the number of frac crews, and the availability of capital to complete these plans and programs); projected natural gas prices, basis and average differential; total resource potential, reserves and EUR; projected production and sales volume and growth rates (including liquids sales volume and growth rates); projected drilling and completions (D&C) costs, other well costs, unit costs and G&A expenses; projected reductions in expenses, capital costs and well costs, the projected timing of achieving such reductions and the Company's ability to achieve such reductions; infrastructure programs; projected capital efficiency and cash savings and other operating efficiencies associated with the Company’s business strategy; the Company’s ability to mitigate curtailments; projected dividend amounts and rates; projected cash flows, including the ability to fund the 2019 drilling program through cash from operations; projected adjusted free cash flow, adjusted operating cash flow, and net income attributable to noncontrolling interests, including the Company’s ownership of Equitrans Midstream Corporation common stock; monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets; the timing and structure of any dispositions of the Company's ownership of common stock of Equitrans Midstream Corporation, and the planned use of the proceeds from any such dispositions; projected capital contributions and capital expenditures; projected adjusted EBITDA; liquidity and financing requirements, including funding sources and availability; the Company’s hedging strategy; and tax position, projected effective tax rate and the impact of changes in tax laws. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently available to the Company. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond the Company’s control. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors,” of the Company’s Form 10-K for the year ended December 31, 2018, as filed with the SEC and as updated by the Company’s Form 10-Q for the quarter ended March 31, 2019, to be filed with the SEC, and any subsequent Form 10-Qs, and those set forth in the other documents the Company files from time to time with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

   

EQT CORPORATION AND SUBSIDIARIES

STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS (UNAUDITED)

 
Three Months Ended
March 31,
2019     2018
Operating revenues: (Thousands, except per share amounts)
Sales of natural gas, oil and NGLs $ 1,271,613 $ 1,226,374
(Loss) gain on derivatives not designated as hedges (131,996 ) 62,592
Net marketing services and other 3,556   23,070  
Total operating revenues 1,143,173 1,312,036
Operating expenses:
Transportation and processing 439,246 416,657
Production 43,408 58,634
Exploration 1,007 1,225
Selling, general and administrative 48,978 39,815
Depreciation and depletion 391,113 392,693
Impairment/loss on sale of long-lived assets 2,329,045
Lease impairments and expirations 29,534 3,879
Proxy and transaction costs 4,089 10,078
Amortization of intangible assets 10,342   10,342  
Total operating expenses 967,717   3,262,368  
Operating income (loss) 175,456 (1,950,332 )
Unrealized gain on investment in Equitrans Midstream Corporation 89,055
Dividend and other income (expense) 20,987 (130 )
Interest expense 56,573   57,911  
Income (loss) from continuing operations before income taxes 228,925 (2,008,373 )
Income tax expense (benefit) 38,234   (429,840 )
Income (loss) from continuing operations 190,691 (1,578,533 )
Income from discontinued operations, net of tax   133,554  
Net income (loss) 190,691 (1,444,979 )
Less: Net income from discontinued operations attributable to noncontrolling interests   141,015  
Net income (loss) attributable to EQT Corporation $ 190,691   $ (1,585,994 )
 
Amounts attributable to EQT Corporation:
Income (loss) from continuing operations $ 190,691 $ (1,578,533 )
(Loss) from discontinued operations, net of tax   (7,461 )
Net income (loss) attributable to EQT Corporation $ 190,691   $ (1,585,994 )
 
Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common stock outstanding 255,046 264,877
Income (loss) from continuing operations $ 0.75 $ (5.96 )
(Loss) from discontinued operations   (0.03 )
Net income (loss) $ 0.75   $ (5.99 )
Diluted:
Weighted average common stock outstanding 255,387 264,877
Income (loss) from continuing operations $ 0.75 $ (5.96 )
(Loss) from discontinued operations   (0.03 )
Net income (loss) $ 0.75   $ (5.99 )
 
   

EQT CORPORATION AND SUBSIDIARIES

PRICE RECONCILIATION

 
Three Months Ended
March 31,
2019     2018
(Thousands, unless noted)
NATURAL GAS
Sales volume (MMcf) 363,717 329,404
NYMEX price ($/MMBtu) (a) $ 3.15 $ 2.98
Btu uplift 0.15   0.20  
Natural gas price ($/Mcf) $ 3.30 $ 3.18
 
Basis ($/Mcf) (b) $ (0.02 ) $ 0.13
Cash settled basis swaps (not designated as hedges) ($/Mcf) (0.12 ) (0.15 )
Average differential, including cash settled basis swaps ($/Mcf) $ (0.14 ) $ (0.02 )
 
Average adjusted price ($/Mcf) $ 3.16 $ 3.16
Cash settled derivatives (not designated as hedges) ($/Mcf) (0.06 ) 0.04  
Average natural gas price, including cash settled derivatives ($/Mcf) $ 3.10 $ 3.20
 
Natural gas sales, including cash settled derivatives $ 1,129,201 $ 1,055,065
 
LIQUIDS
NGLs (excluding ethane):
Sales volume (MMcfe) (c) 12,549 18,391
Sales volume (Mbbls) 2,091 3,065
Price ($/Bbl) $ 29.86 $ 37.50
Cash settled derivatives (not designated as hedges) ($/Bbl) 1.65   (1.21 )
Average NGLs price, including cash settled derivatives ($/Bbl) $ 31.51 $ 36.29
NGLs sales $ 65,903 $ 111,236
Ethane:
Sales volume (MMcfe) (c) 5,938 7,997
Sales volume (Mbbls) 990 1,333
Price ($/Bbl) $ 7.23   $ 7.90  
Ethane sales $ 7,152 $ 10,532
Oil:
Sales volume (MMcfe) (c) 1,266 1,213
Sales volume (Mbbls) 211 202
Price ($/Bbl) $ 38.67   $ 55.15  
Oil sales $ 8,160 $ 11,146
 
Total liquids sales volume (MMcfe) (c) 19,753 27,601
Total liquids sales volume (Mbbls) 3,292 4,600
 
Liquids sales $ 81,215 $ 132,914
 
TOTAL PRODUCTION
Total natural gas & liquids sales, including cash settled derivatives (d) $ 1,210,416 $ 1,187,979
Total sales volume (MMcfe) 383,470 357,005
Average realized price ($/Mcfe) $ 3.16 $ 3.33
 
(a)   The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/MMBtu) was $3.15 and $3.00 for the three months ended March 31, 2019 and 2018, respectively.
(b) Basis represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.
(c) NGLs, ethane and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
(d) Also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.
 

Analyst inquiries please contact:
Blake McLean – Senior Vice President, Investor Relations and Strategy
412.395.3561
[email protected]

Media inquiries please contact:
Linda Robertson – Media Relations Manager
412.553.7827
[email protected]


Source: Business Wire (April 25, 2019 - 6:30 AM EDT)

News by QuoteMedia
www.quotemedia.com

Recent Company Earnings:


May 1, 2019

More capacity coming: another $3.5 billion of projects now under construction will go into service in 2019

Houston’s Enterprise Products Partners L.P. (stock ticker: EPD, $EPD) reported record net income attributable to limited partners of $1.3 billion, or $0.57 per unit on a fully diluted basis for Q1 2019.

2018’s Q1 net income came in at $901 million, or $0.41 per unit on a fully diluted basis, for comparison. The company said cash flow from operations was $1.2 billion for both the first quarters of 2019 and 2018. Both Adjusted EBITDA and DCF, which exclude the effects of non-cash, mark-to-market earnings, increased 18% to $2.0 billion and $1.6 billion, respectively, the company said.

Jim Teague, CEO of Enterprise’s general partner said his team made it possible for the company to set eleven operational and financial records during the quarter.

Teague said the business saw a benefit from production increases in the Permian and Haynesville shale regions.

All of the Permian’s projected 700,000 BOPD 2019 production volume increase will be exported overseas – Teague

“Our crude oil marine terminals reported record volumes of nearly 900,000 barrels per day in the first quarter of 2019 despite the temporary closure of the Houston Ship Channel. With Permian crude oil volumes forecasted to increase by approximately 700,000 barrels per day in 2019, we believe substantially all of this increase in volumes will be destined for international markets.”

He said that Enterprise expects 300,000 barrels per day of new ethane demand from ethylene facilities on the U.S. Gulf Coast forecasted to begin operations during the remainder of 2019.

“Through April 2019, we placed $1.9 billion of growth capital projects into service. We have another $5.0 billion of major growth assets under construction of which we expect to put $3.5 billion of these projects into service between now and the end of the year.”

These projects include:

  • a third train at the Orla natural gas processing complex in the Permian,
  • a tenth NGL fractionator and an isobutane dehydrogenation (iBDH) plant at our Mont Belvieu complex.
  • crude oil, natural gas, NGL and petrochemical pipelines,
  • natural gas processing plants in the Permian,
  • a second PDH facility, and
  • the Texas deep water crude oil port.

“With the flexibility to self-fund our equity needs and strong balance sheet, we believe these new projects will enable us to increase cash flow per unit and the equity value of our partnership,” Teague said.

Read the full Q1 Earnings Release here.

April 25, 2019

EQT Reports First Quarter 2019 Results

Lilis Energy Achieves First Quarter 2019 Production Guidance and Provides Operational Update

QEP Reports First Quarter 2019 Financial and Operating Results

March 25, 2019

Sinopec’s Net Profit Up Over 20% to RMB 61.6 Billion in 2018

March 14, 2019

2018 Earnings season gets ready for a wrap

As oil and gas earnings are getting ready for the wrap party, a group of middle market producers and a proppant company announced earnings in the past few days, with key points summarized in brief below.

Earnings in Brief: Six E&Ps and a Sand Supplier Announce 2018 Wins, Losses - Oil & Gas 360

Earnings in Brief: Six E&;Ps and a Sand Supplier Announce 2018 Wins, Losses – Oil & Gas 360

Mid-Con Energy Partners

Mid-Con Energy Partners, LP (NASDAQ: MCEP) announced operating and financial results for the fourth quarter and full year ended December 31, 2018.

“2018 was a transformative year for the Partnership,” commented President and CEO, Jeff Olmstead. “We significantly improved our financial position by extending the maturity of our Revolving Credit Facility, increasing the borrowing base amount, reducing total outstanding debt, and reducing our total leverage as calculated by our banks. We closed approximately $23 million in acquisitions, including several properties in our new core area of Wyoming, and expanded our footprint in Oklahoma. This all resulted in production increasing approximately 30% from the first quarter of 2018 compared to the fourth quarter of 2018.

In February 2019, we announced the execution of two agreements to sell substantially all of our Texas assets and to acquire assets in Oklahoma. The net effect of this transaction will be to significantly reduce outstanding debt and to add long-lived, low-decline assets with potential for margin enhancements through operational efficiency to our portfolio. This continues our track record from 2018 of entering into transactions that help strengthen our financial position and lower our base PDP decline rate. The lower PDP decline rate provides us a more stable reserve base, which allows for more operational and financial control, to grow from. Lower decline properties require less capital investment to maintain production and reserves, and provide the flexibility to invest additional free cash flow into development of new reserves and/or into new acquisitions.

Recent Events and 2018 Summary

  • Completed $15.0 million private offering (the “Offering”) of Class B Convertible Preferred Units (“Class B Preferred Units”) on January 31, 2018, to investors led by John Goff. The Partnership used a portion of net proceeds from this Offering to acquire assets in the Powder River Basin(“PRB Acquisitions”) and the remaining approximately $7.2 million to pay down debt.
  • Closed approximately $23 million, after post-close adjustments, in acquisitions during 2018. The acquisitions included entering into a new core area consisting of two basins, the Powder River Basin and the Big Horn Basin, as well as increasing our footprint in Oklahoma. These properties consist of approximately 9,271 MBoe of net total proved reserves as of December 31, 2018 at the standardized measure for pricing approved by the SEC (“SEC pricing”).
  • In February 2019, we executed definitive agreements to sell substantially all of our Eastern Shelf assets in Texas for $60.0 million, and to acquire Oklahoma properties in Osage, Caddo, and Grady counties for $27.5 million, both subject to customary purchase price adjustments. The properties include 10 mature waterflood units and consist of low decline (average PDP decline of less than 5%), long-lived assets with opportunities to both grow production and decrease current operating expenses through operational efficiencies. Net proved developed producing reserves of these Oklahoma properties as of January 1, 2019 were 6.2 MMBoe (96% oil) based on SEC pricing as of January 1, 2019.
  • On December 19, 2018, the Partnership’s borrowing base was increased to $135.0 million as part of the regularly scheduled semi-annual redetermination.
  • We reduced total debt outstanding at December 31, 2018 by $6.0 million, or 6.1%, from December 31, 2017 and in January 2018 the revolving credit facility maturity was extended by two years to November 2020. Compliance Total Leverage, as calculated per our credit agreement, was approximately 3.17x as of December 31, 2018 compared to 3.54x as of December 31, 2017.
  • Fourth quarter 2018 average daily production of 3,663 Boe/d, an increase of 30.8% from first quarter 2018.
  • Lease operating expenses (“LOE”) of approximately $22.5 million, an increase of 8.3% year-over-year.
  • Realized revenues, inclusive of cash settlements from matured derivatives and net premiums, were $59.0 million, an increase of 8.2% year-over-year.
  • Full year net loss of $18.3 million in 2018 compared to a net loss of $27.3 million in 2017.
  • Adjusted EBITDA, a non-GAAP measure, was $25.2 million at December 31, 2018, an increase of 5.7% year-over-year, primarily due to higher oil and gas revenue from an increase in commodity prices.

Earthstone Energy

Earthstone Energy, Inc. (NYSE: ESTE) announced financial and operating results for the fourth quarter and year ended December 31, 2018.

Fourth Quarter 2018 Highlights

  • Revenues of $41.2 million
    • Increased 16% over fourth quarter 2017
  • Average daily production of 10,454 Boepd(1)
    • Increased 15% over fourth quarter 2017 while the oil component increased 27% over fourth quarter 2017
  • Net income of $81.0 million
    • Compared to $5.5 million in fourth quarter 2017
  • Net income attributable to Earthstone Energy, Inc. of $36.1 million, or $1.26 per diluted share
    • Compared to $2.3 million, or $0.09 per diluted share in fourth quarter 2017
  • Adjusted EBITDAX(2)of $23.9 million
    • Increased 8% over fourth quarter 2017

Full Year 2018 Highlights

  • Revenues of $165.4 million
    • Increased by 53% over 2017
  • Average daily production of 9,937 Boepd(1)
    • Increased by 26% over 2017 while the oil component increased 30% over 2017
  • Net income of $95.2 million
    • Compared to a net loss of $44.7 million in 2017
  • Net income attributable to Earthstone Energy, Inc. of $42.3 million, or $1.50 per diluted share
    • Compared to a net loss of $12.5 million, or a $0.53 loss per share in 2017
  • Adjusted EBITDAX(2)(3)of $96.2 million
    • Increased by 59% over 2017

Robert J. Anderson, President of Earthstone, said, “2018 was a very successful year for Earthstone as we keenly focused on operating efficiencies and thereby generated low-cost reserve additions and strong cash margins. We realized significant improvement in every metric including production, revenues and operating expenses, thus driving a 59% increase in Adjusted EBITDAX to $96.2 million for the year. We also increased our proved reserves by 24% with a finding and development cost of only $9.49 per Boe for extensions and discoveries. Considering that we have only been operating in the Midland Basin for less than two years, we are pleased with our accomplishments and the contributions of all of our employees.

“For 2019, we have set high expectations for Earthstone as we build on these successes. Our strong balance sheet, substantial hedge position averaging over $65 per barrel of oil and positive operating margins give us the confidence to increase our capital budget by approximately 25%, allowing us the flexibility to continue to demonstrate the quality of our acreage position through the drill bit.

“We are executing a successful one-rig development program in the Midland Basin and expect to continue our multi-year growth in production, although our 2019 production profile is projected to remain lumpy with a majority of the completions scheduled in the second half of the year. We presently estimate that we will achieve free cash flow in 2020 assuming we maintain our existing pace of development and current commodity prices continue through such time.”


Abraxas Petroleum

Abraxas Petroleum Corporation (NASDAQ:AXAS) reported financial and operating results for the three and twelve months ended December 31, 2018.

Financial Highlights for the Three Months Ended December 31, 2018

The three months ended December 31, 2018 resulted in:

  • Production of 965 MBoe (10,493 Boepd)
  • Revenue of $36.0 million
  • Net income of $55.8 million, or $ 0.34 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $4.1 million, or $ 0.02 per share
  • EBITDA(a)of $20.1 million
  • Adjusted EBITDA per bank loan covenants of $20.1 million(a)

The twelve months ended December 31, 2018 resulted in:Financial Highlights for the Twelve Months Ended December 31, 2018

  • Production of 3.6 MMBoe (9,809 Boepd)
  • Revenue of $149.2 million
  • Net income of $57.8 million, or $ 0.35 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $30.7 million, or $ 0.19 per share
  • EBITDA(a)of $83.9 million
  • Adjusted EBITDA per bank loan covenants of $84.2 million(a)

Williston Basin, North Dakota

Western North Dakota has experienced one of the coldest winters on record. Abraxas has experienced several days when all surface work was shut down due to temperatures and wind chill that put personnel safety and equipment reliability in jeopardy. The Ravin NE Pad is still under production restriction due to a natural gas pipeline installation delay requiring the flaring of all gas production from this pad. The pipeline is scheduled to be in service within the next two weeks at which point we are expecting normal production operations to be resumed. The Abraxas Raven Rig#1 is scheduled to be started up within the next several months to begin drilling operations on the six well Jore Extension Pad.

Delaware Basin, West Texas

In the Delaware Basin of West Texas, the Company has successfully drilled, completed and started flowback on the two well Creosote Pad in Ward County, where Abraxas now owns an approximate 95% working interest. The Wolfcamp A-1 and A-2 were targeted with a 26 stage fracture treatment (frac) in 5,000’ laterals. The one well Hackberry pad has been successfully drilled and a 26 stage fracture treatment in the Wolfcamp A-1 is scheduled to start next Monday. Abraxas owns an approximate 75% working interest in this 5,000’ lateral well located in Winkler County. The Company is currently drilling a two well pad, Woodberry, in which we own a 100% working interest. The Woodberry Pad adjoins our Caprito block in Ward County.

Year End 2018 Reserves

The Company’s total proved reserves at December 31, 2018 were 67.2 million barrels of oil equivalent (MMBOE), an increase of 2.8% over year end 2017 after production of 3.6 MMBOE and property divestitures of 3.8 MMBOE. The SEC PV10 (a non-GAAP measure) was approximately $689 million. SEC pricing was $65.56 per barrel for oil and $3.03 per mcf for gas. Proved developed reserves were 24.6 MMBOE, or 37% of the total. Oil represented 63% of total proved reserves, natural gas 22%, and natural gas liquids 15%.


Midstates Petroleum

Midstates Petroleum Company, Inc. (NYSE: MPO) announced fourth quarter and full year 2018 results.

Fourth Quarter and Full-Year 2018 Highlights and Recent Key Items

  • Reported net income of $49.8 million, or $1.91 per share, for the full year 2018 and net income of $35.8 million, or $1.38 per share, in the fourth quarter 2018
  • Announced year-end 2018 SEC proved reserves of 72.4 million barrels of oil equivalent (MMBoe) with a net present value discounted at 10% (PV-10) of approximately $580 million
    • Year-end 2018 SEC proved developed producing (PDP) reserves of 46.5 MMBoe with a PV-10 of approximately $425 million
  • Achieved Mississippian Lime production of 16,747 barrels of oil equivalent per day (Boepd) for the full year 2018
  • Generated Adjusted EBITDA of $27.8 million in the fourth quarter of 2018, outpacing quarterly operational capital expenditures by approximately $24.2 million; full-year 2018 Adjusted EBITDA totaled $116.4 million, approximately $19.9 million higher than full-year operational capital expenditures
  • Initiated a process pursuing all strategic and opportunistic transactions that create significant shareholder value
  • Completed workforce reduction in January 2019 to better align general and administrative costs (G&A) with current activity levels; reduced Adjusted Cash G&A expense by $4 million to $5 million annually (excluding one-time severance costs)
  • Successfully executed $50 million tender offer for outstanding capital stock in February 2019, returning capital to shareholders

For the fourth quarter of 2018, Midstates reported net income of $35.8 million, or $1.38 per share, which included the impact of a $25.4 million gain related to the Company’s commodity derivative contracts. In the same period in 2017, the Company reported a net loss of $121.0 million, or ($4.78) per share, including the impact of a $5.1 million commodity derivative charge, and in the third quarter of 2018 reported net income of $11.5 million, or $0.44 per share, including the impact of a $6.6 million commodity derivative charge. For the full year 2018, Midstates reported net income of $49.8 million, or $1.91 per share, which included the impact of a $3.6 million gain related to the Company’s commodity derivative contracts, compared to a net loss of $85.1 million, or ($3.39) per share, including the impact of a $3.7 million gain related to the Company’s commodity derivative contracts, in 2017.

In the fourth quarter of 2018, Midstates generated Adjusted EBITDA of $27.8 million, excluding advisory fees and costs incurred for strategic reviews. This compares to $33.9 million for the same quarter in 2017 and $31.9 million for the third quarter of 2018. For the full year 2018, Midstates generated Adjusted EBITDA of $116.4 million, excluding advisory fees and costs incurred for strategic reviews, compared to $128.2 million, in 2017.

David Sambrooks, President and Chief Executive Officer, commented, “In 2018 we continued our strong operational results and strengthened Midstates financially through several notable accomplishments. Operationally, we optimized base production through a substantial workover program and have taken actions to drive down lease operating and overhead expenses to help maximize margins and grow value. Midstates generated $116.4 million in Adjusted EBITDA, outpacing our operational capex by $20 million and we monetized a portion of our portfolio by selling our non-core Anadarko asset, using the proceeds and free cash flow to pay down $105 million in debt during 2018.

“We are forecasting significant free cash flow generation in 2019, which allowed us to successfully execute a $50 million tender offer earlier this year and affords us the opportunity to consider multiple options moving forward, including returning a substantial portion of our excess cash to our shareholders. As we look to the future, we remain committed to optimizing our production, minimizing costs and operating efficiently, as well as actively pursuing all opportunities that enhance us financially and operationally.”

Operational Update

Midstates ceased drilling at the end of the third quarter of 2018 in order to further study the production results of its recent extended lateral wells. With the erosion of commodity prices in the fourth quarter of 2018, the Company elected to continue the pause in drilling through mid-year 2019 to maximize free cash flow generation from its producing properties and will evaluate future development plans as the Company moves forward.

The Company did not bring online any new saltwater disposal injection wells during the fourth quarter of 2018. Midstates is currently operating 11 non-Arbuckle injection wells in Woods and Alfalfa Counties, Oklahoma, with permitted injection capacity of approximately 240,000 barrels of water per day. The Company’s total permitted injection capacity in all formations in Woods and Alfalfa Counties, Oklahoma, which may differ from actual injection capacity due to operational constraints, is approximately 372,000 barrels of water per day. The Company’s current disposal rate into all formations is approximately 135,000 barrels of water per day. Approximately 45% of the Company’s water injection is currently being injected into non-Arbuckle formations.

Production and Pricing

Production during the fourth quarter of 2018 totaled 16,351 Boepd, compared with 17,996 Boepd during the third quarter of 2018. Oil volumes comprised 27% of total production, natural gas liquids (NGLs) 26%, and natural gas 47% during the fourth quarter of 2018. Production for the full year 2018 totaled 20,326 Boepd, compared with 22,148 Boepd for the full year 2017. Production from the Company’s Mississippian Lime properties contributed approximately 82%, or 16,747 Boepd, and the Anadarko Basin properties contributed approximately 18%, or 3,579 Boepd. Midstates divested its Anadarko Basin properties in the second quarter of 2018. For the total Company, oil volumes comprised 29% of total production, natural gas liquids (NGLs) 25%, and natural gas 46% for the full year 2018.


Oryx Petroleum

Oryx Petroleum Corporation Limited announced its financial and operational results for the year ended December 31, 2018. All dollar amounts set forth in this news release are in United States dollars, except where otherwise indicated.

2018 Financial Highlights:

  • Total revenues of $97.6 million on working interest sales of 1,542,300 barrels of oil (“bbl”) and an average realised sales price of $57.00/bbl for 2018
    • 160% annual increase in revenues versus 2017
    • Q4 2018 revenues increased 24% versus Q3 2018
    • The Corporation has received full payment in accordance with production sharing contract entitlements for all oil sale deliveries into the Kurdistan Region Export Pipeline through November 2018
  • Operating expenses of $19.2 million ($12.48/bbl) and an Oryx Petroleum Netback1of $21.68/bbl
    • 37% decrease in operating expenses per barrel versus 2017
  • Profit of $43.8 million ($0.09 per common share) in 2018 versus loss of $39.1 million in 2017 ($0.11 per common share)
    • Improvement primarily attributable to higher netback and impairment reversal
  • Net cash generated by operating activities was $8.1 million versus net cash used in operating activities of $9.7 million in 2017 comprised of Operating Funds Flow2of $23.2 million partially offset by a $15.1 millionincrease in non-cash working capital
  • Net cash used in investing activities during 2018 was $32.8 million including payments related to drilling and facilities work in the Hawler license area, seismic processing and interpretation costs in the AGC Central license area, and partially offset by a decrease in non-cash working capital
  • $14.4 million of cash and cash equivalents as of December 31, 2018

2018 Operations Highlights:

  • Average gross (100%) oil production of 6,500 bbl/d (working interest 4,200 bbl/d) for the year ended December 31, 2018 vs 3,300 bbl/d (working interest 2,100 bbl/d) for the year ended December 31, 2017
    • 97% increase in gross (100%) oil production in 2018 versus 2017; 46% increase in gross (100%) oil production in Q4 2018 versus Q3 2018
    • Successful completion of six producing wells during the year
    • Commencement of production from the Tertiary and Cretaceous reservoirs at the Banan field
  • Gross (working interest) proved plus probable oil reserves of 127 million barrels as at December 31, 2018
    • 4% increase versus 2017
  • Processing and interpretation of 3D seismic data covering the AGC Central license area completed with prospects remapped and ranked
    • Best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels as at December 31, 2018

2019 Operations Update:

  • Average gross (100%) oil production of 11,400 bbl/d (working interest 7,400 bbl/d) and 9,800 bbl/d (working interest 6,300 bbl/d) in January and February 2019, respectively. Production in February was curtailed for a number of days due to a temporary shut-down of the Kurdistan Region Export Pipeline.
  • The Banan-6 appraisal well targeting the Cretaceous reservoir is expected to be spudded in the coming days. The well is expected to be drilled to a measured depth of 1,840 metres and completed as a producing well.
  • Final prospect ranking has been completed in the AGC Central license area with an environmental impact assessment planned for 2019 with preparation for drilling in 2020 to follow

 Oryx Petroleum’s Chief Executive Officer, Vance Querio, said, “2018 was a good year for Oryx Petroleum. During the year we substantially increased production from the Hawler license area thanks to the successful completion of six new producing wells, increasing production from the Zey Gawra Cretaceous reservoir and commencing production from both the Cretaceous and Tertiary reservoirs in the Banan field.

“We continued to refine our prospect inventory in the AGC Central license area with the remapping of 23 prospects in six structures. We have also identified and ranked a series of wells that will allow us to start exploring the license that has best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels.”


Chaparral Energy

Chaparral Energy, Inc. (NYSE: CHAP) announced its fourth quarter and full year 2018 financial and operational results with the filing of its form 10-K. The company will hold its financial and operating results call this morning, March 14 at 9 a.m. Central.

2018 Highlights

  • Recorded 2018 full year STACK production of 14.5 thousand barrels of oil equivalent per day (MBoe/d), representing a 52% year-over-year increase
  • Achieved 2018 full year total company production of 20.5 MBoe/d
  • Reported full year 2018 net income of $33.4 million, or 73 cents per diluted share
  • Achieved full year 2018 adjusted EBITDA, as defined below, of $125 million
  • Grew 2018 total proved reserves to 94.8 million barrels of oil equivalent (MMBoe), which adjusted for 2018 divestitures marks a 35% year-over-year increase, and represents a PV-10 value of $686 million
  • Increased STACK proved reserves by 50% year-over-year to 74.1 MMBoe, while replacing 519% of STACK production
  • Invested $194.7 million in STACK drilling and completion (D&C) activities in 2018
  • Reduced total company lease operating expense per barrel of oil equivalent (LOE/Boe) almost $4 from $10.96 in 2017 to $7.24 in 2018
  • Strengthened the balance sheet by issuing $300 million of unsecured senior notes and increasing the borrowing base to $325 million in 2018

“Our team is extremely proud of all we accomplished in 2018,” said Chief Executive Officer Earl Reynolds. “From strategically adding to our STACK acreage position to uplisting to the New York Stock Exchange to successfully completing a $300 million senior notes offering and increasing our borrowing base, we were able to increase the value of our assets while also strengthening our balance sheet. In addition, our outstanding operational and drilling results allowed us to significantly grow production and reserves in 2018.”

“While we continue to monitor market conditions and plan to be flexible with our capital expenditures, our current plan for 2019 is to invest $275 to $300 million in capital, more than 80% of which is dedicated to low-cost, high-return STACK/Merge D&C activity. “

Operational Update – STACK Production Soars in 2018

Chaparral increased its STACK production to 16.6 MBoe/d during the fourth quarter, which is up 6% as compared to the previous quarter. Full year STACK production grew by 52% to 14.5 MBoe/d compared to the previous year. Total company production was 21.7 MBoe/d during the fourth quarter, which is a 2% quarter-over-quarter increase. Total company production for the full year was 20.5 MBoe/d, which represents an 11% decrease from the previous year. Excluding production from divested EOR assets in 2017, total company production increased by 13% on a year-over-year basis. Total company production for 2018 was 36% oil, 25% natural gas liquids (NGLs) and 39% natural gas.


Smart Sand

  • 4Q and full year 2018 revenue of $52.2 million and $212.5 million, respectively.
  • 4Q and full year 2018 total tons sold of approximately 610,000 and 2,995,000, respectively.
  • 4Q and full year 2018 net (loss) income of $(4.4) million and $18.7 million, respectively.
  • 4Q and full year 2018 Adjusted EBITDA of $18.7 million and $66.0 million, respectively.

Smart Sand, Inc. (NASDAQ: SND), a producer of high quality Northern White raw frac sand and provider of proppant logistics solutions through both our in-basin transloading terminal and wellsite storage solutions, announced results for the fourth quarter and full year ended December 31, 2018.

Charles Young, Smart Sand’s Chief Executive Officer, stated, “Smart Sand had a good quarter and we’ve responded well to the challenging conditions in the fourth quarter. We recently contracted two sets of last mile storage solutions and have two additional sets ready to be deployed. Our investment in the Van Hook terminal in the Bakken is a strong contributor to our operating performance. We remained focused on our long-term objectives and we’ve proven that we’re profitable through all operating cycles with consistent results of operations. Looking forward, we plan to stay the course in continuing to execute on our already-profitable plan to provide long-term value to the Company, our employees, our customers, and our shareholders.”

Full Year 2018 Highlights

Revenues of $212.5 million for the full year 2018 were the highest in the history of the Company representing a 55% increase over full year 2017 revenue of $137.2 million.  The increase in revenues was primarily due to higher sales volumes resulting from increased exploration and production activity, higher average selling prices of proppant due to increased in-basin sales generated from our Van Hook terminal in the Bakken and favorable price adjustments under certain take-or-pay contracts based on the Average Cushing Oklahoma WTI Spot prices.

Overall tons sold were approximately 2,995,000 in the full year 2018, compared to full year 2017 volume of 2,449,000 tons. Tons sold increased by 22.3% due to increased exploration and production activity in the oil and natural gas industry in 2018 compared to 2017.

Net income was $18.7 million, or $0.46 per basic share and $0.46 per diluted share, for the full year 2018, compared with net income of $21.5 million, or $0.54 per basic share and $0.53 per diluted share, for the full year 2017, a decrease of 13% year over year.

 

 

February 26, 2019

Magnolia Oil & Gas Corporation Announces Fourth Quarter and 2018 Year-End Results

Ring Energy Releases Fourth Quarter and Twelve Month 2018 Financial and Operational Results

February 22, 2019

Cabot Oil & Gas Corporation Establishes Several New Full-Year Records, Returns $1.0 Billion to Shareholders, Repays $304 Million of Debt

February 20, 2019

Energy Transfer Reports Fourth Quarter 2018 Results with Record Performance and Continued Growth

February 19, 2019

Noble Energy, Inc. (NYSE:NBL) Chairman and CEO David Stover said today that the oil and gas industry needs to prioritize capital discipline and corporate returns over top-line production growth.

“Our 2019 capital program and early 2020 outlook aligns capital investment with the environment and sets the stage for Noble Energy to generate sustainable organic free cash flow in 2020 and beyond,” Stover said.

Stover said Noble’s U.S. onshore business is anticipated to be self-funding by the end of 2019 and will underpin the company’s production growth of five to ten percent per year, before the additional impact of major projects.

“We will be completing spend for Leviathan, offshore Israel, this year and commencing production and cash flow from the project by the end of the year,” Stover said in a statement.

“Our early 2020 outlook provides over $500 million in free cash flow(1) at strip pricing, which we plan to return to shareholders through the dividend and share repurchase program.”

Highlights from the company’s 2019 plan include:

  • Organic capital expenditures funded by Noble Energy are planned at a range of $2.4 to $2.6 billion, 17 percent lower at the midpoint compared to 2018.
  • Total company volumes are anticipated in the range of 345-365 MBoe/d, an increase of 5 percent(3)at the midpoint as compared to 2018.
  • The Company’s U.S. onshore business is anticipated to deliver asset-level free cash flow(2)by the end of 2019, while delivering total volume growth of approximately 10 percent(3) and oil production growth of 13 percent(3) from 2018 levels.
  • First gas sales from Leviathan are expected by the end of 2019, delivering substantial production and cash flow growth in 2020.

 

Noble’s plans for organic capital expenditures by area (in $MM) are estimated to be:

United States Onshore 1,600 – 1,700
NBL-funded Midstream 100 – 125
Eastern Mediterranean 550 – 600
West Africa 100 – 125
Other 50
Total 2,400 – 2,600

Sixty percent of the Company’s total organic capital for 2019 is expected to be spent in the first half of the year due to the timing of Leviathan spend and U.S. onshore activity. Excluded from the amounts above is an estimated $195 million of Noble Midstream Partners’ (NYSE: NBLX) capital, which will be consolidated into Noble Energy. Third-party customer activity represents 65 percent of the NBLX capital.

U.S. Onshore

Approximately 90 percent of Noble Energy’s U.S. onshore capital will be focused in the DJ and Delaware Basins. Activity in the DJ Basin includes progressing the second row of development in Mustang, which benefits from the Company’s approved Comprehensive Drilling Plan and access to multiple gas processing providers. In addition, Noble Energy expects to bring online a number of pads within Wells Ranch and East Pony. In the Delaware, operated activity is focused on row development primarily in the Wolfcamp A and Third Bone Spring zones. The Company will continue to optimize base production and cash flows from the Eagle Ford.

Noble Energy expects to commence production in 2019 on between 165-175 wells across the U.S. onshore, including 95-100 in the DJ Basin, 50-55 in the Delaware Basin and approximately 20 in the Eagle Ford. The second and third quarter are planned to have a higher count of wells commencing production as compared to the first and fourth quarters of the year.

The Company anticipates full-year 2019 average U.S. onshore sales volumes of between 262 and 278 thousand barrels of oil equivalent per day (MBoe/d). Combined, production from the DJ and Delaware Basins is expected to increase throughout 2019, up 15 to 20 percent(3) on a full year basis. Sales volumes in the Eagle Ford are anticipated to be lower on a full year basis, with volumes growing from the first half to the second half of the year.

Compared to the second half of 2018, Noble Energy expects capital costs per well in 2019 to be lower by 10 to 15 percent. The majority of these costs savings have been realized through operational efficiencies and lower service costs.

International Offshore

Offshore, the Company is focused on maintaining its strong base production and cash flow in Israel and Equatorial Guinea (E.G.), while progressing the Leviathan project offshore Israel for first gas sales by the end of the year. In addition, Noble Energy expects to sanction the Alen gas monetization project in E.G. in the first half of 2019, with first gas sales estimated for the first half of 2021.

In Israel, gross natural gas sales volumes are anticipated to be flat to up slightly from 2018, reflecting the nearly fully utilized capacity of the Tamar field on an annual basis. Organic capital expenditures in the Eastern Mediterranean primarily comprise spending to complete the Leviathan project. Excluded from the Company’s organic capital expenditures guidance are costs related to an acquisition of interest in the EMG pipeline, which provides a connection point for the export of natural gas from Israel to Egypt.

In E.G., sales volumes are expected to be lower than 2018 due to natural field declines through the year and anticipated downtime for the third-party LNG facility turnaround in the first quarter. The Company’s 2019 capital expenditure guidance includes initial costs for the Alen gas monetization project as well an additional development well at the Aseng oil field to help mitigate field decline. First production from the Aseng development well is anticipated in the third quarter of 2019.

The Company’s new guidance for 2019 replaces its prior 2019 and multi-year outlook, it said in a press release.

First Quarter 2019 Guidance

The Company anticipates sales volumes in the first quarter in the range of 321 to 336 MBoe/d. In E.G., sales volumes are anticipated to be lower than the fourth quarter 2018 by approximately 15 MBoe/d as a result of the timing of oil liftings (production is anticipated to be greater than sales) and the turnaround maintenance at the third-party LNG facility. The variance from the fourth quarter 2018 is estimated to be 40 percent from oil volumes and 60 percent from natural gas volumes, which will also result in equity method investment income being lower than prior quarters.

U.S. onshore sales volumes in the first quarter 2019 are also anticipated to be slightly lower than the fourth quarter 2018 as a result of the timing of well activities in late 2018 and early 2019. The first quarter is planned to be the low quarter for wells commencing production in 2019. Natural decline in the Eagle Ford will also impact the first quarter 2019. Second half U.S. onshore production is anticipated to be approximately 15 percent higher than the first half of the year.

The Company’s planned first quarter organic capital expenditures of between $725 and $800 million are anticipated to be the highest quarter of 2019, driven by the timing of drilling and completion activities in the U.S. onshore business as well as Leviathan spend.

Additional full-year and first quarter 2019 guidance details are available in the latest presentation deck provided on the ‘Investors’ page of the Company’s website, www.nblenergy.com.

Noble  announces 2018 results

Noble also announced full-year 2018 financial and operating results.

Full year 2018 Highlights

  • Returned more than $500 million to shareholders, including $295 million through the Company’s share repurchase program and $208 million through Noble Energy’s quarterly dividend.
  • Strengthened the Company’s balance sheet by paying down $609 million in Noble Energy debt.
  • Enhanced the portfolio to focus on high-return U.S. onshore liquids and international gas by divesting the Company’s Gulf of Mexico assets and midstream ownership in Appalachia.
  • Sales volumes totaled 353 MBoe/d, up 11 percent(1)as compared to 2017, on organic capital expenditures funded by Noble Energy of less than $3 billion.
  • Implemented row development in the DJ and Delaware Basins and grew U.S. onshore oil production 26 percent(1)as compared to 2017.
  • Received approval for the first large-scale Comprehensive Drilling Plan across the Company’s Mustang area in the DJ Basin.
  • Progressed the Leviathan project, offshore Israel, to approximately 75 percent complete.
  • Executed gas sales agreements for up to 700 MMcf/d of natural gas, gross, to customers in Egypt from the Tamar and Leviathan fields.
  • Negotiated Heads of Agreement to progress monetization of natural gas from the Alen field in Equatorial Guinea.

Enable Midstream Announces Fourth Quarter and Full-Year 2018 Financial and Operating Results

February 7, 2019

PANHANDLE OIL AND GAS INC. Reports First Quarter 2019 Results

February 1, 2019

Sizeable profits: ExxonMobil adds $20.8 billion, Chevron $14.8 billion, Shell $21.4 billion

Royal Dutch Shell (stock ticker: RDSA, $RDSA), ExxonMobil (stock ticker: XOM, $XOM) and Chevron (stock ticker: CVX, $CVX) have all reported 2018 earnings during the previous 24 hours.

Shell earns $21.4 billion profit for the year

Royal Dutch Shell started things off, reporting unaudited results yesterday, including full year earnings of $21.4 billion for 2018, which reflected higher realized oil, gas and LNG prices, partly offset by movements in deferred tax positions.

Cash flow from operating activities for the fourth quarter 2018 was $22.0 billion, which included positive working capital movements of $9.1 billion, mainly as a result of a fall in crude oil price and lower inventory levels. Excluding working capital movements, cash flow from operations of $12.9 billion mainly reflected increased earnings, compared with the fourth quarter 2017, Shell said.

Shell upstream

During the quarter, Shell completed the sale of its Upstream interests in Ireland, as well as the disposal of its interests in the Draugen and Gjøa fields in Norway.

In December, Shell and its partners renewed a number of onshore oil mining leases in the Niger Delta for 20 years (Shell interest 30%).

Read Shell’s full press release here.


Exxon tallies $20.8 billion profit

Exxon reported 2018 earnings of $20.8 billion, or $4.88 per share assuming dilution, compared with $19.7 billion a year earlier. Excluding U.S. tax reform and asset impairments, earnings were $21 billion, compared with $15.3 billion in 2017. Cash flow from operations and asset sales was $40.1 billion, including proceeds associated with asset sales of $4.1 billion. Capital and exploration expenditures were $25.9 billion, including incremental spend to accelerate value capture.

Exxon said its fourth quarter 2018 earnings were $6 billion, or $1.41 per share assuming dilution, compared with $8.4 billion in the prior-year quarter. Earnings excluding U.S. tax reform and impairments were $6.4 billion, compared with $3.7 billion in the prior-year quarter.

Exxon Q4 upstream

  • Crude prices weakened in the fourth quarter, while natural gas prices strengthened with higher LNG prices and increased seasonal demand.
  • Natural gas volumes were supported by stronger seasonal gas demand in Europe.
  • Permian unconventional production continued to ramp up in the fourth quarter, with production up more than 90 percent from the same period last year.

Read Exxon’s full press release here.


Chevron captures $14.8 billion profit for 2018

  • Record annual net oil-equivalent production of 2.93 million barrels per day, 7 percent higher than a year earlier; 4 to 7 percent growth targeted for 2019
  • Reserves replacement of 136 percent
  • Dividend increase of $0.07 per share
  • Share repurchases of $1.0 billion in fourth quarter

Chevron ticked off earnings of $3.7 billion ($1.95 per share – diluted) for fourth quarter 2018, compared with $3.1 billion ($1.64 per share – diluted) in the fourth quarter of 2017, which included $2.02 billion in tax benefits related to U.S. tax reform. Included in the current quarter was an asset write-off totaling $270 million. Foreign currency effects increased earnings in the 2018 fourth quarter by $268 million.

Full-year 2018 earnings were $14.8 billion ($7.74 per share – diluted), the company said, compared with $9.2 billion ($4.85 per share – diluted) in 2017. Included in 2018 were impairments and other charges of $1.59 billion and a gain on an asset sale of $350 million. Foreign currency effects increased earnings in 2018 by $611 million.

Chevron said its sales and other operating revenues in Q4 were $40 billion, compared to $36 billion in the year-ago period.

Chevron U.S. upstream

Chevron’s U.S. upstream operations earned $964 million in fourth quarter 2018, compared with $3.69 billion a year earlier. The decrease was primarily due to the absence of the prior year benefit of $3.33 billion from U.S. tax reform, partially offset by higher crude oil production and realizations, Chevron said in a statement.

The company’s average sales price per barrel of crude oil and natural gas liquids was $56 in fourth quarter 2018, up from $50 a year earlier. The average sales price of natural gas was $2.01 per thousand cubic feet in fourth quarter 2018, up from $1.86 in last year’s fourth quarter.

Net oil-equivalent production of 858,000 barrels per day in fourth quarter 2018 was up 187,000 barrels per day from a year earlier.

Production increases from shale and tight properties in the Permian Basin in Texas and New Mexico and base business in the Gulf of Mexico were partially offset by normal field declines and the impact of asset sales of 17,000 barrels per day. The net liquids component of oil-equivalent production in fourth quarter 2018 increased 30 percent to 674,000 barrels per day, while net natural gas production increased 20 percent to 1.10 billion cubic feet per day.

Read Chevron’s full press release here.

On a side note…

The U.S.’s largest independent exploration and production company announced its fourth quarter results yesterday. ConocoPhillips (stock ticker: COP) ($COP) showed earnings of $1.9 billion, or $1.61 per share for the quarter.

For the year, ConocoPhillips earned $6.3 billion in 2018, or $5.32 per share. [Editor’s note: COP’s earnings were not included in the profit tally above; that was strictly generated by the three integrated international oils.]

Conoco has been firing on all cylinders since mid-2017, and has reported six straight quarters of profits, the first time the company has achieved this since Q3 2014. 2018 also represents the first yearly profit Conoco reported since 2014, as its 2017 results were hampered by a major impairment.

Conoco reported it now holds 5.3 billion BOE of reserves, up from 5.0 billion BOE last year. The company replaced 147% of production, with oil accounting for over 90% of new reserves.

Read about Conoco’s good year here.

 


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