Cabot Oil & Gas Announces Best Year in Nearly Three Decades

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 February 22, 2019 - 6:30 AM EST
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Cabot Oil & Gas Corporation Establishes Several New Full-Year Records, Returns $1.0 Billion to Shareholders, Repays $304 Million of Debt

HOUSTON, Feb. 22, 2019 /PRNewswire/ -- Cabot Oil & Gas Corporation (NYSE: COG) ("Cabot" or the "Company") today announced the best year of its nearly three-decade public company history that provided record financial results, the culmination and in-service of several long-dated infrastructure initiatives, and continued momentum on the free cash flow front.

"In early 2018 we reaffirmed our commitment to creating long-term shareholder value through disciplined capital allocation by announcing a strategy focused on delivering debt-adjusted per share growth, generating positive free cash flow, improving corporate returns on capital employed, increasing return of capital to shareholders, and maintaining a strong balance sheet," stated Dan O. Dinges, Chairman, President and Chief Executive Officer. "I am happy to say that our 2018 program delivered on this strategy on all fronts."

Full-Year 2018 Highlights

New Records 

  • Net income of $557.0 million (or $1.25 per share); adjusted net income (non-GAAP) of $531.2 million (or $1.19 per share)
  • Free cash flow (non-GAAP) of $296.6 million, marking the third consecutive year of positive free cash flow
  • Production of 735.0 billion cubic feet equivalent (Bcfe), an increase of seven percent year-over-year (14 percent on a divestiture-adjusted basis)
  • Proved reserves of 11.6 trillion cubic feet equivalent (Tcfe), an increase of 19 percent year-over-year (25 percent on a divestiture-adjusted basis)
  • Operating expenses per unit of $1.76 per thousand cubic feet equivalent (Mcfe), a 13 percent improvement year-over-year

Other Strategic Milestones

  • Return on capital employed (ROCE) (non-GAAP) of 15.9 percent, an improvement of 860 basis points year-over-year
  • Returned approximately $1.0 billion of capital to shareholders through dividends and share repurchases, including a 40 percent increase in the quarterly dividend per share and an eight percent reduction in shares outstanding
  • Retired $304 million of senior notes at maturity, resulting in annualized interest expense savings of $21.8 million
  • Total company all-sources finding and development costs of $0.30 per Mcfe and Marcellus-only all-sources finding and development costs of $0.26 per thousand cubic feet (Mcf)
  • Reduced debt-to-EBITDAX to 1.0x at year-end 2018

See the supplemental tables at the end of this press release for a reconciliation of non-GAAP measures including adjusted net income, EBITDAX, discretionary cash flow, free cash flow, ROCE, pre-tax present value of future net cash flows (pre-tax PV–10) and net debt to adjusted capitalization ratio.

Fourth-Quarter 2018 Financial Results

Fourth-quarter 2018 daily equivalent production was 2,243 million cubic feet equivalent (Mmcfe) per day (100 percent natural gas), a 20 percent increase relative to the fourth-quarter of 2017 and an 11 percent sequential increase relative to the third-quarter of 2018. On a divestiture-adjusted basis, fourth-quarter 2018 daily equivalent production increased 26 percent relative to the prior-year comparable quarter.

Fourth-quarter 2018 net income was $275.0 million, or $0.64 per share, compared to net loss of $44.4 million, or $0.10 per share, in the prior-year period. Fourth-quarter 2018 adjusted net income (non-GAAP) was $235.8 million, or $0.55 per share, compared to adjusted net income of $59.5 million, or $0.13 per share, in the prior-year period. Fourth-quarter 2018 EBITDAX (non-GAAP) was $463.1 million, compared to $259.8 million in the prior-year period.

Fourth-quarter 2018 net cash provided by operating activities was $316.1 million, compared to $179.1 million in the prior-year period. Fourth-quarter 2018 discretionary cash flow (non-GAAP) was $492.8 million, compared to $240.1 million in the prior-year period. Fourth-quarter 2018 free cash flow (non-GAAP) was $241.4 million, compared to $28.7 million in the prior-year period. "Our free cash flow for the fourth-quarter exceeded our initial forecast of $200 million, driven by stronger than anticipated price realizations," commented Dinges.

Fourth-quarter 2018 natural gas price realizations, including the impact of derivatives, were $3.11 per Mcf, an increase of 43 percent compared to the prior-year period. Excluding the impact of derivatives, fourth-quarter 2018 natural gas price realizations were $3.22 per Mcf, representing a $0.42 discount to NYMEX settlement prices compared to a $0.78 discount in the prior-year comparable quarter.

Fourth-quarter 2018 operating expenses (including financing) decreased to $1.87 per Mcfe, a seven percent improvement compared to the prior-year period.  All operating expenses per unit were in-line with the Company's guidance for the quarter except for depreciation, depletion and amortization and exploration, driven by higher amortization of undeveloped leasehold and exploratory dry hole costs associated with unsuccessful drilling results in our exploration areas. "After further evaluation of our remaining exploration prospect, we have determined that this area is unlikely to yield results that generate long-term value creation for our shareholders," noted Dinges.  "As we have said through this entire evaluation process, we remain committed to deploying capital judiciously and if a project fails to generate competitive full-cycle returns, then we will not allocate additional capital to it going forward."

Cabot incurred a total of $223.0 million of capital expenditures in the fourth-quarter of 2018 including $207.6 million of drilling and facilities capital; $2.4 million of leasehold acquisition capital; and $13.0 million of other capital. Additionally, the Company contributed $4.4 million to its equity method pipeline investments in the fourth-quarter of 2018. See the supplemental table at the end of this press release reconciling the capital expenditures during the fourth-quarter of 2018.

Full-Year 2018 Financial Results

Full-year 2018 daily equivalent production was 2,014 Mmcfe per day (99 percent natural gas), a seven percent increase relative to the prior-year period. On a divestiture-adjusted basis, daily equivalent production for the full-year 2018 increased 14 percent relative to the prior-year period.

Full-year 2018 net income was $557.0 million, or $1.25 per share, compared to net income of $100.4 million, or $0.22 per share in the prior-year period. Adjusted net income (non-GAAP) was $531.2 million, or $1.19 per share, compared to adjusted net income of $244.5 million, or $0.53 per share, in the prior-year period. Full-year 2018 EBITDAX (non-GAAP) was $1.3 billion, compared to $1.1 billion in the prior-year period.

Full-year 2018 net cash provided by operating activities was $1,104.9 million, compared to $898.2 million in the prior-year period. Full-year 2018 discretionary cash flow (non-GAAP) was $1,268.4 million, compared to $976.1 million in the prior-year period. Full-year 2018 free cash flow (non-GAAP) was $296.6 million, compared to $154.5 million in the prior-year period. Full-year 2018 ROCE (non-GAAP) improved to 15.9 percent, compared to 7.3 percent in the prior-year period.

Full-year 2018 natural gas price realizations, including the impact of derivatives, were $2.54 per Mcf, an increase of 10 percent compared to the prior-year period.  Excluding the impact of derivatives, full-year 2018 natural gas price realizations were $2.58 per Mcf, representing a $0.51 discount to NYMEX settlement prices.

Full-year 2018 operating expenses (including financing) decreased to $1.76 per Mcfe, a 13 percent improvement compared to the prior-year period.

Cabot incurred a total of $816.1 million of capital expenditures in 2018 including $758.9 million of drilling and facilities capital; $29.9 million of leasehold acquisition capital; and $27.3 million of other capital. Additionally, the Company contributed $77.3 million to its equity method pipeline investments in 2018. See the supplemental table at the end of this press release reconciling the capital expenditures for the year.

Capital Allocation Update

During the fourth-quarter of 2018, Cabot repurchased 11.3 million shares at a weighted-average share price of $22.92, resulting in full-year 2018 repurchases of approximately 38.5 million shares at a weighted-average share price of $23.48. Since reactivating the share repurchase program in the second-quarter of 2017, Cabot has reduced its shares outstanding by over nine percent to 423.4 million shares. "During the year, we returned approximately $1.0 billion of capital to shareholders via dividends and share repurchases, representing a total shareholder yield of over nine percent based on our current market capitalization," said Dinges. "We expect to continue to be an industry leader in shareholder yield as we execute on our strategy of returning at least 50 percent of free cash flow to shareholders annually."

Financial Position and Liquidity

As of December 31, 2018, Cabot had total debt of $1.2 billion and cash on hand of $2.3 million. During the fourth-quarter of 2018, Cabot paid off its $67.0 million tranche of 9.78% senior notes that matured on December 1, 2018. For the full-year, the Company retired $304 million of senior notes that matured in 2018, resulting in annualized interest expense savings of $21.8 million.

The Company's debt-to-total capitalization ratio and debt-to-trailing twelve months EBITDAX ratio were 37.0 percent and 1.0x, respectively, compared to 37.6 percent and 1.4x as of December 31, 2017. The Company currently has $7.0 million outstanding under the credit facility, resulting in approximately $1.8 billion of liquidity.

Year-End 2018 Proved Reserves

Cabot reported year-end proved reserves of 11.6 Tcfe, an increase of 19 percent over year-end 2017. Specific highlights from the Company's year-end reserve report include:

  • Total company all-sources finding and development costs of $0.30 per Mcfe
  • Marcellus-only all-sources finding and development costs of $0.26 per Mcf
  • Marcellus-only all-sources reserve replacement of 414 percent

The table below reconciles the components driving the 2018 reserve increase:

Proved Reserves Reconciliation (in Bcfe)



Balance at December 31, 2017


9,726


Revisions of prior estimates


780


Extensions, discoveries and other additions


2,244


Sales


(410)


Production


(735)


Balance at December 31, 2018


11,605


As of December 31, 2018, 100 percent of Cabot's year-end proved reserves were natural gas and were located in the Marcellus Shale. Approximately 64 percent of the year-end proved reserves were classified as proved developed and 36 percent were classified as proved undeveloped (PUD), including five percent of drilled and uncompleted PUDs.

Total costs incurred during 2018 were $902.7 million, which included $778.6 million for development costs, $94.3 million for exploration costs, and $29.9 million for lease acquisition costs.

The SEC price used for reporting Cabot's year-end 2018 proved reserves, which has been adjusted for basis and quality differentials, was $2.58 per Mcf for natural gas, representing an 11 percent year-over-year increase. Assuming the SEC prices, the pre-tax PV–10 (non-GAAP) of the year-end 2018 proved reserves was $8.1 billion. "Our latest year-end proved reserves disclosure further demonstrates the strong underlying economics and repeatability of our low-cost position in Northeast Pennsylvania," commented Dinges.  "Our 25 percent growth in Marcellus reserves at industry-leading finding costs was accomplished with primarily only three rigs and two completion crews, highlighting the low capital intensity of this world-class asset."

Upper Marcellus Operations Update

The Company drilled and completed nine Generation 5 Upper Marcellus wells in the field during 2018. Based on the production data gathered to date, these wells on average have demonstrated an improvement over the average estimated ultimate recovery (EUR) per thousand lateral feet of 2.9 billion cubic feet (Bcf) from our earlier generation completions. "Given the limited sample size and production history, we plan to continue to allocate a small portion of our capital program annually to testing our Generation 5 completions in the Upper Marcellus in an effort to gather more production history from a larger sample of wells before updating our expected EURs; however, the long-term plan of fully-developing the Lower Marcellus before beginning full-development mode in the Upper Marcellus remains unchanged," stated Dinges. "Most importantly, our results from the 2018 wells reconfirmed what our previous Upper Marcellus results have demonstrated over the years, which is that we have two distinct, highly-economic intervals across our acreage position in Northeast Pennsylvania."

First-Quarter and Full-Year 2019 Guidance

Cabot has provided its first-quarter 2019 production guidance range of 2,250 to 2,275 Mmcfe per day. The Company has also updated its 2019 production growth guidance to 20 percent (27 percent on a debt-adjusted per share basis). This production growth is based on an updated capital budget of $800 million. Approximately $160 million of the 2019 capital budget relates to wells that are drilled and / or completed in 2019 but not placed on production until 2020. "While we continue to emphasize our focus on improving return on capital employed, generating significant free cash flow, and increasing our return of capital to shareholders, we also believe our unique, low-cost asset base in the Marcellus Shale allows us to deliver on these objectives while also continuing to invest in the disciplined, organic growth of our business to enhance long-term shareholder value, assuming market conditions warrant it," commented Dinges.

Based on a range of $2.50 and $3.00 per Mmbtu NYMEX prices for 2019, the Company has included its estimated key financial metrics for the year below. "Despite the current NYMEX strip for the year implying an outcome at the higher-end of this price range, we have highlighted that even at the low-end of the range our 2019 program can deliver financial metrics that are not only top-tier across all oil and gas companies but are also extremely competitive across the broader equity markets," noted Dinges.

Estimated Key Financial Metrics1

$2.50 NYMEX

$2.75 NYMEX

$3.00 NYMEX

Adjusted Earnings Per Share Growth (%)

20% - 35%

40% - 55%

60% - 75%

Free Cash Flow ($mm)

$475 - $525

$600 - $650

$700 - $750

Return on Capital Employed (%)

19% - 21%

21% - 23%

24% - 26%





(1) Ranges for estimated key financial metrics based on guidance ranges for operating expenses

Conference Call Webcast

A conference call is scheduled for Friday, February 22, 2019, at 9:30 a.m. Eastern Time to discuss fourth-quarter and full-year 2018 financial and operating results. To access the live audio webcast, please visit the Investor Relations section of the Company's website. A replay of the call will also be available on the Company's website.

Cabot Oil & Gas Corporation, headquartered in Houston, Texas, is a leading independent natural gas producer with its entire resource base located in the continental United States. For additional information, visit the Company's website at www.cabotog.com.

This press release includes forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements regarding future financial and operating performance and results, returns to shareholders, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect", "project", "estimate", "believe", "anticipate", "intend", "budget", "plan", "forecast", "outlook", "predict", "may", "should", "could", "will" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (SEC) filings. See "Risk Factors" in Item 1A of the Form 10-K and subsequent public filings for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.  Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not undertake any obligation to correct or update any forward-looking statement, whether as the result of new information, future events or otherwise, except as required by applicable law.

FOR MORE INFORMATION CONTACT

Matt Kerin (281) 589-4642

OPERATING DATA



Quarter Ended

December 31,


Twelve Months Ended

December 31,


2018


2017


2018


2017

PRODUCTION VOLUMES








Natural gas (Bcf)

206.3



164.4



729.9



655.6


Crude oil and condensate (Mbbl)

—



1,238.0



754.0



4,440.9


Natural gas liquids (NGLs) (Mbbl)

—



131.5



75.1



512.1


Equivalent production (Bcfe)

206.3



172.6



735.0



685.3


Daily equivalent production (Mmcfe/day)

2,243



1,876



2,014



1,878










AVERAGE SALES PRICE








Natural gas, including hedges ($/Mcf)

$

3.11



$

2.18



$

2.54



$

2.31


Natural gas, excluding hedges ($/Mcf)

$

3.22



$

2.15



$

2.58



$

2.30


Crude oil and condensate, including hedges ($/Bbl)

$

—



$

54.54



$

63.68



$

48.16


Crude oil and condensate, excluding hedges ($/Bbl)

$

—



$

54.77



$

64.68



$

47.81


NGL ($/Bbl)

$

—



$

23.51



$

21.51



$

19.47










AVERAGE UNIT COSTS ($/Mcfe)








Direct operations

$

0.08



$

0.14



$

0.09



$

0.15


Transportation and gathering

0.68



0.69



0.68



0.70


Taxes other than income

0.03



0.04



0.03



0.05


Exploration

0.22



0.03



0.15



0.03


Depreciation, depletion and amortization

0.63



0.83



0.57



0.83


General and administrative (excluding stock-based compensation)

0.07



0.11



0.09



0.09


Stock-based compensation

0.08



0.05



0.05



0.05


Interest expense

0.08



0.12



0.10



0.12



$

1.87



$

2.01



$

1.76



$

2.02


















WELLS DRILLED(1)








Gross

37



20



97



91


Net

35.1



20.0



95.1



82.5










WELLS COMPLETED(1)








Gross

33



24



94



105


Net

32.0



24.0



93.0



94.2


_______________________________________________________________________________

(1)

Wells drilled represents wells drilled to total depth during the period. Wells completed includes wells completed during the period, regardless of when they were drilled.

 

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)



Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands, except per share amounts)

2018


2017


2018


2017

OPERATING REVENUES








Natural gas

$

663,547



$

353,989



$

1,881,150



$

1,506,078


Crude oil and condensate

—



67,810



48,722



212,338


Gain (loss) on derivative instruments

46,060



(29,427)



44,432



16,926


Brokered natural gas

6,155



4,957



209,530



17,217


Other

539



3,174



4,314



11,660



716,301



400,503



2,188,148



1,764,219


OPERATING EXPENSES








Direct operations

16,889



24,125



69,646



102,310


Transportation and gathering

140,883



119,530



496,731



481,439


Brokered natural gas

5,761



4,990



184,198



15,252


Taxes other than income

7,208



6,925



22,642



33,487


Exploration

45,654



4,903



113,820



21,526


Depreciation, depletion and amortization

129,269



143,128



417,479



568,817


Impairment of oil and gas properties(1)

—



414,256



—



482,811


General and administrative (excluding stock-based compensation)

15,113



19,022



63,494



63,745


Stock-based compensation(2)

15,516



7,863



33,147



34,041



376,293



744,742



1,401,157



1,803,428


Earnings (loss) on equity method investments(3)

2,146



(96,500)



1,137



(100,486)


(Gain) loss on sale of assets

(1,477)



1,933



(16,327)



(11,565)


INCOME (LOSS) FROM OPERATIONS

340,677



(438,806)



771,801



(151,260)


Interest expense, net

15,624



20,410



73,201



82,130


Other expense (income)

116



18



463



(4,955)


Income (loss) before income taxes

324,937



(459,234)



698,137



(228,435)


Income tax expense (benefit)(4)

49,893



(414,793)



141,094



(328,828)


NET INCOME (LOSS)

$

275,044



$

(44,441)



$

557,043



$

100,393


Earnings (loss) per share - Basic

$

0.64



$

(0.10)



$

1.25



$

0.22


Weighted-average common shares outstanding

430,978



462,371



445,538



463,735


_______________________________________________________________________________

(1)

 Includes the impairment of our Eagle Ford Shale oil and gas properties in south Texas in the fourth quarter of 2017.

(2)

Includes the impact of our performance share awards and restricted stock.

(3)

Includes the $95.9 million other than temporary impairment of our investment in Constitution.

(4)

Includes the impact of the remeasurement of our net deferred income tax liabilities based on the new corporate income tax rate associated with the Tax Act in the fourth quarter of 2017. The remeasurement resulted in an income tax benefit of $242.9 million.

 

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)


(In thousands)

December 31,
 2018


December 31,
 2017

ASSETS




Current assets

$

544,545



$

764,957


Properties and equipment, net (Successful efforts method)

3,463,606



3,072,204


Assets held for sale

—



778,855


Other assets

190,678



111,328



$

4,198,829



$

4,727,344






LIABILITIES AND STOCKHOLDERS' EQUITY




Current liabilities

$

287,264



$

630,050


Long-term debt, net (excluding current maturities)

1,226,104



1,217,891


Deferred income taxes

458,597



227,030


Liabilities held for sale

—



15,748


Other liabilities

138,705



112,720


Stockholders' equity

2,088,159



2,523,905



$

4,198,829



$

4,727,344



 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)



Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands)

2018


2017


2018


2017

CASH FLOWS FROM OPERATING ACTIVITIES








Net income (loss)

$

275,044



$

(44,441)



$

557,043



$

100,393


Deferred income tax expense (benefit)

97,804



(410,844)



229,603



(321,113)


Impairment of oil and gas properties

—



414,256



—



482,811


(Gain) loss on sale of assets

1,477



(1,933)



16,327



11,565


Exploratory dry hole cost

41,316



978



97,741



3,820


(Gain) loss on derivative instruments

(46,060)



29,427



(44,432)



(16,926)


Net cash received (paid) in settlement of derivative instruments

(21,277)



4,469



(41,631)



8,056


Income charges not requiring cash

144,500



248,231



453,712



707,496


Changes in assets and liabilities

(176,753)



(61,030)



(163,460)



(77,942)


Net cash provided by operating activities

316,051



179,113



1,104,903



898,160










CASH FLOWS FROM INVESTING ACTIVITIES








Capital expenditures

(246,967)



(177,745)



(894,470)



(764,558)


Proceeds from sale of assets

2,825



82,733



678,350



115,444


Investment in equity method investments

(4,397)



(33,657)



(77,263)



(57,039)


Net cash used in investing activities

(248,539)



(128,669)



(293,383)



(706,153)










CASH FLOWS FROM FINANCING ACTIVITIES








Net borrowings (repayments) of debt

(60,000)



—



(297,000)



—


Treasury stock repurchases

(291,036)



(55,486)



(872,761)



(123,741)


Dividends paid

(30,184)



(23,131)



(111,369)



(78,838)


Tax withholding on vesting of stock awards

(82)



(2,044)



(8,150)



(7,973)


Other

—



8



—



50


Net cash used in financing activities

(381,302)



(80,653)



(1,289,280)



(210,502)










Net decrease in cash and cash equivalents

$

(313,790)



$

(30,209)



$

(477,760)



$

(18,495)



Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results, the results of our peers and of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations throughout this release of GAAP financial measures to non-GAAP financial measures for the periods indicated.

We have also included herein certain forward-looking non-GAAP financial measures. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant.

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings Per Share

Adjusted Net Income (Loss) and Adjusted Earnings per Share are presented based on our belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. Adjusted Net Income (Loss) and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP.


Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands, except per share amounts)

2018


2017


2018


2017

As reported - net income (loss)

$

275,044



$

(44,441)



$

557,043



$

100,393


Reversal of selected items:








Impairment of oil and gas properties(1)

—



414,256



—



482,811


Impairment of equity method investments(2)

—



95,945



—



95,945


(Gain) loss on sale of assets

1,477



(1,933)



16,327



11,565


(Gain) loss on derivative instruments(3)

(67,337)



33,896



(86,063)



(8,870)


Stock-based compensation expense

15,516



7,863



33,147



34,041


Severance expense

—



21



28



3,213


OPEB curtailment

—



(67)



—



(4,917)


Interest expense related to income tax reserves

(538)



—



3,116



—


Tax effect on selected items

11,619



(203,211)



7,637



(226,787)


Impact of 2017 tax reform

—



(242,875)



—



(242,875)


Adjusted net income

$

235,781



$

59,454



$

531,235



$

244,519


As reported - earnings (loss) per share

$

0.64



$

(0.10)



$

1.25



$

0.22


Per share impact of selected items

(0.09)



0.23



(0.06)



0.31


Adjusted earnings per share

$

0.55



$

0.13



$

1.19



$

0.53


Weighted-average common shares outstanding

430,978



462,371



445,538



463,735


_______________________________________________________________________________

(1)

This amount represents the non-cash impairment of our Eagle Ford Shale oil and gas properties located in south Texas in the fourth quarter of 2017.

(2)

This amount represents the non-cash other than temporary impairment of our investment in Constitution recorded in Loss on equity method investments in the Condensed Consolidated Statement of Operations.

(3)

This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

Return on Capital Employed

Return on Capital Employed (ROCE) is defined as adjusted net income (loss) (defined above) plus after-tax net interest expense divided by average capital employed, which is defined as total debt plus stockholders' equity. ROCE is presented based on our belief that this non-GAAP measure is useful information to investors when comparing our profitability and the efficiency with which we have employed capital over time relative to other companies. ROCE is not a measure of financial performance under GAAP and should not be considered an alternative to net income.

 

(In thousands)


2018


2017

Interest expense, net


$

73,201



$

82,130


Less: Interest expense related to income tax reserves (1)


(3,116)



—


Tax benefit on interest expense, net


(16,004)



(30,346)


After-tax interest expense, net (A)


54,081



51,784







As reported - net income (loss)


557,043



100,393


Adjustments to as reported - net income (loss), net of tax


(25,808)



144,126


Adjusted net income (loss) (B)


531,235



244,519







Adjusted net income (loss) before interest expense, net (A + B)


$

585,316



$

296,303







Total debt - beginning


$

1,521,891



$

1,520,530


Stockholders' equity - beginning


2,523,905



2,567,667


Capital employed - beginning


4,045,796



4,088,197







Total debt - ending


1,226,104



1,521,891


Stockholders' equity - ending


2,088,159



2,523,905


Capital employed - ending


3,314,263



4,045,796







Average capital employed (C)


$

3,680,030



$

4,066,997







Return on average capital employed (ROCE) (A+B) / C


15.9

%


7.3

%

_______________________________________________________________________________

(1)

 Interest expense related to income tax reserves is included in the adjustments to as reported - net income, net of tax.

Discretionary Cash Flow and Free Cash Flow Calculation and Reconciliation

Discretionary Cash Flow is defined as net cash provided by operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company's ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary Cash Flow is presented based on our belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income.

Free Cash Flow is defined as Discretionary Cash Flow (defined above) less capital expenditures and investment in equity method investments. Free Cash Flow is an indicator of a company's ability to generate cash flow after spending the money required to maintain or expand its asset base. Free Cash Flow is presented based on our belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to net income.



Quarter Ended
 December 31,


Twelve Months Ended

December 31,

(In thousands)


2018


2017


2018


2017

Net cash provided by operating activities


$

316,051



$

179,113



$

1,104,903



$

898,160


Changes in assets and liabilities


176,753



61,030



163,460



77,942


Discretionary cash flow


492,804



240,143



1,268,363



976,102


Capital expenditures


(246,967)



(177,745)



(894,470)



(764,558)


Investment in equity method investments


(4,397)



(33,657)



(77,263)



(57,039)


Free cash flow


$

241,440



$

28,741



$

296,630



$

154,505


EBITDAX Calculation and Reconciliation

EBITDAX is defined as net income plus loss on debt extinguishment, interest expense, other expense, income tax expense, depreciation, depletion and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, earnings and loss on equity method investments, and stock-based compensation expense. EBITDAX is presented based on our belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. EBITDAX is not a measure of financial performance under GAAP and should not be considered as alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.


Quarter Ended

December 31,


Twelve Months Ended

December 31,

(In thousands)

2018


2017


2018


2017

Net income (loss)

$

275,044



$

(44,441)



$

557,043



$

100,393


Plus (less):








Interest expense, net

15,624



20,410



73,201



82,130


Other expense (income)

116



18



463



(4,955)


Income tax expense (benefit)

49,893



(414,793)



141,094



(328,828)


Depreciation, depletion and amortization

129,269



143,128



417,479



568,817


Impairment of oil and gas properties

—



414,256



—



482,811


Exploration

45,654



4,903



113,820



21,526


(Gain) loss on sale of assets

1,477



(1,933)



16,327



11,565


Non-cash (gain) loss on derivative instruments

(67,337)



33,896



(86,063)



(8,870)


(Earnings) loss on equity method investments

(2,146)



96,500



(1,137)



100,486


Stock-based compensation

15,516



7,863



33,147



34,041


EBITDAX

$

463,110



$

259,807



$

1,265,374



$

1,059,116


Net Debt Reconciliation

The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders' equity. This ratio is a measurement which is presented in our annual and interim filings and we believe this ratio is useful to investors in determining our leverage. Net Debt is calculated by subtracting cash and cash equivalents from total debt. Net Debt and the Net Debt to Adjusted Capitalization ratio are non-GAAP measures which we believe are also useful to investors since we have the ability to and may decide to use a portion of our cash and cash equivalents to retire debt. Additionally, as we may incur additional expenditures without increasing debt, it is appropriate to apply cash and cash equivalents to debt in calculating the Net Debt to Adjusted Capitalization ratio.

(In thousands)

December 31,
 2018


December 31,
 2017

Current portion of long-term debt

$

—



$

304,000


Long-term debt, net

1,226,104



1,217,891


Total debt

$

1,226,104



$

1,521,891


Stockholders' equity

2,088,159



2,523,905


Total capitalization

$

3,314,263



$

4,045,796






Total debt

$

1,226,104



$

1,521,891


Less: Cash and cash equivalents

(2,287)



(480,047)


Net debt

$

1,223,817



$

1,041,844






Net debt

$

1,223,817



$

1,041,844


Stockholders' equity

2,088,159



2,523,905


Total adjusted capitalization

$

3,311,976



$

3,565,749






Total debt to total capitalization ratio

37.0

%


37.6

%

Less: Impact of cash and cash equivalents

—

%


8.4

%

Net debt to adjusted capitalization ratio

37.0

%


29.2

%

Capital Expenditures



Quarter Ended
December 31,


Twelve Months Ended
December 31,

(In thousands)


2018


2017


2018


2017

Cash paid for capital expenditures


$

246,967



$

177,745



$

894,470



$

764,558


Change in accrued capital costs


17,326



(2,309)



19,346



(3,516)


Exploratory dry hole cost


(41,316)



(978)



(97,741)



(3,820)


Capital expenditures


$

222,977



$

174,458



$

816,075



$

757,222


Pre-tax Present Value of Future Net Cash Flows Calculation and Reconciliation

(In thousands)

December 31,
 2018


December 31,
 2017

Standardized Measure of Discounted Future Net Cash Flows

$

6,483,308



$

5,010,446


Plus: Future Income Tax Expenses, discounted at 10% annual rate

1,651,488



955,240


Pre-tax Present Value of Future Net Cash Flows, discounted at 10% annual rate

$

8,134,796



$

5,965,686


 

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SOURCE Cabot Oil & Gas Corporation


Source: PR Newswire (February 22, 2019 - 6:30 AM EST)

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Recent Company Earnings:

November 5, 2019

Source: Reuters

(Reuters) – Chesapeake Energy Corp , once the second-largest U.S. natural gas producer, warned on Tuesday about its ability to continue as a going concern as the debt-laden company struggles with falling prices for the commodity.

Chesapeake Energy raises 'going concern' doubts-oag360

Source: chk.com

Shares of Chesapeake fell 13% to $1.35 in early trading, with the company earlier in the day also having reported a marginally bigger than expected loss and a huge shortfall in production for the third quarter.

Chesapeake has about $10 billion in debt, nearly four times its market valuation. Much of that is a result of big spending when energy prices were high and acquisitions aimed at expanding in the oil-heavy Powder River Basin to combat falling natural gas prices.

The company said its ability to meet debt covenants in the next 12 months will be affected if oil and natural gas prices continue to remain low. (bit.ly/34yczbo)

A continuous rise in U.S. gas production – a byproduct of the shale oil boom – has prices for the fuel heading toward a 25-year low, with output outpacing U.S. consumption.

The company said average realized natural gas price fell 11.5% to $2.38 per thousand cubic feet in the third quarter.

Total production fell nearly 11% to 478,000 barrels of oil equivalent per day (boe/d) from a year earlier and missed analysts’ expectations of 490,664 boe/d.

Adjusted net loss attributable to the company was $188 million, or 11 cents per share, in the third quarter ended Sept. 30 from a loss of $8 million, or 1 cent per share, a year earlier.

Analysts on average had expected the company to report a loss of 10 cents per share.

The Oklahoma-based firm expects capital expenses to range from $1.3 billion to $1.6 billion for 2020, well below $2.11 billion to $2.31 billion set aside for 2019.

The company also plans to cut its 2020 production costs as well as general and administrative expenses by about 10% while expecting flat oil production year over year.

Source: Reuters

HOUSTON (Reuters) – Pioneer Natural Resources Chief Executive Scott Sheffield said on Tuesday that he expects the Permian Basin, the top U.S. shale field, to “slow down significantly over the next several years.”

Top shale CEO says OPEC shouldn't worry about U.S. oil growth-oag360

Source: pxd.com

“I don’t think OPEC has to worry that much more about U.S. shale growth long term,” Sheffield said on Tuesday on a call with analysts.

U.S. shale fields have driven domestic production to all time highs, prompting OPEC to cut production to keep global prices stable. But U.S. producers are under pressure to trim spending and return profits to shareholders through dividends and share buybacks.

Despite new production coming from Norway, Brazil and Guyana in the next year, “there’s not much coming on after” that, Sheffield said, adding that he is “becoming more optimistic that we’re probably at the bottom end of the cycle” in oil prices.

November 1, 2019

Source: Houston Chronicle

Exxon Mobil Corp. profits fell in the third quarter, the company reported Friday.

Exxon Mobil's profits fall in third quarter-oag360

Source: Houston Chronicle

The Irving, Texas-based oil major reported a third-quarter net profit of $3.17 billion, little more than half the profit the company reported in the same quarter last year.

Exxon reported $65.05 billion of revenue in the third quarter, down from $76.61 billion in the same quarter last year.

Still, the energy giant beat Wall Street expectations. Exxon reported earning 75 cents per share; analysts expected earnings of 67 cents a share.

Oil-equivalent production rose 3 percent from the third quarter of 2018, to 3.9 million barrels per day. Liquids production increased 4 percent, driven by Permian Basin growth, and natural gas volumes increased 1 percent.

Production in the Permian Basin increased 7 percent in the third quarter.

“We are making excellent progress on our long-term growth strategy,” said Darren W. Woods, chairman and chief executive officer in a statement.

October 30, 2019

Source: Reuters

(Reuters) – Hess Corp (HES.N) reported a quarterly loss on Wednesday, as lower oil and gas prices limited gains from higher production, sending its shares down nearly 5%.

https://www.reuters.com/article/us-hess-results/hess-posts-loss-as-lower-oil-prices-cap-production-gains-idUSKBN1X91CD-oag360

Source: Reuters/Andrew Cullen

The results come a day after shale player Concho Resources Inc (CXO.N) posted adjusted earnings that more than halved on the back of tumbling prices.

Hess said average prices for crude, including hedging, fell more than 15% in the third quarter, while it dropped 7% for natural gas.

Global oil prices fell in the third quarter on oversupply and demand concerns fueled by the U.S.-China trade war and its impact on the global economy.

The results come a day after shale player Concho Resources Inc (CXO.N) posted adjusted earnings that more than halved on the back of tumbling prices.

Hess said average prices for crude, including hedging, fell more than 15% in the third quarter, while it dropped 7% for natural gas.

Global oil prices fell in the third quarter on oversupply and demand concerns fueled by the U.S.-China trade war and its impact on the global economy.

Oil and gas net production rose to an average of 290,000 barrels of oil equivalent per day (boepd), excluding Libya, from 279,000 boepd a year earlier.

The increased production was driven by a 38% jump in Bakken output that partially offset the hit from hurricane in the Gulf of Mexico.The higher output at Bakken also prompted the company to raise its full-year net production guidance to about 285,000 boepd, from 275,000 boepd to 280,000 boepd it forecast earlier.

Hess also cut its 2019 capital expenditure by $100 million to $2.7 billion.

The company posted an adjusted net loss of $98 million, or 32 cents per share, in the third quarter ended Sept. 30, compared with a profit of $29 million, or 6 cents per share, a year earlier.

Analyst on average expected a loss of 33 cents, according to IBES data from Refinitiv.

Shares of the company were 4.2% lower at $62.96 amid a broader fall in oil prices that dragged the S&P energy index .SPNY down 1.1%.

October 29, 2019

Source: Reuters

(Reuters) – U.S. Silica Holdings shares plunged 33% after the frac sand miner said it expects demand to slow in the fourth quarter and reported a bigger-than-expected quarterly loss on Tuesday, weighed down by lower prices.

Prices for the proppant used to crack the ground and extract oil have dropped in North America as oil producers drill and complete fewer wells under investor pressure to spend less, and as the market struggles with an oversupply in the aftermath of the shale boom.

https://www.reuters.com/article/us-u-s-silica-results/u-s-silica-sees-lower-frac-sand-demand-shares-tumble-idUSKBN1X812J-oag360

Source: ussilica.com

“Energy markets deteriorated further and faster than expected during the quarter as E&P budget exhaustion slowed completion activity, resulting in lower demand and pricing pressure,” Chief Executive Officer Bryan Shinn said on a post-earnings call with analysts.

While sand sales to oil and gas customers fell 1% sequentially, pricing was “significantly lower” with new mines coming online in West Texas and overcrowding the market, the company said.

Volumes in the current quarter are expected to decline at least 10% sequentially, while prices are expected to fall further, it added.

However, Shinn expects to see a rebound in oil field completions by the middle of the first quarter next year, as oil and gas producers reset their budgets.

The company also forecast net sales and profits in its industrial business, which supplies sand to construction companies and glass manufacturers, to stay flat or rise marginally in 2020, hurt by trade tariffs and fears of a global slowdown.

U.S. Silica reported a net loss of $23 million, or 31 cents per share, for the quarter ended Sept. 30, compared with a profit of $6.3 million, or 8 cents per share, a year earlier.

Excluding items, loss of 17 cents per share missed analysts’ average estimate of 3 cents, according to Refinitiv IBES data.

Revenue fell 14.5% to $361.8 million, also missing estimate of $395.5 million.

The company now expects 2019 spending to be less than $125 million it had forecast earlier, and plans to spend between $40 million and $60 million next year.

October 25, 2019

Reuters

Phillips 66 beat analysts’ estimates for quarterly profit on Friday, as the refiner benefited from higher retail fuel margins, sending its shares up 4.4% to their highest in more than a year.

The Houston, Texas-based company, which retails fuel under brand names such as Conoco, 76 and JET, buys refined products from the market and resells them across its about 9,000 outlets spread across the United States and Europe.

https://www.reuters.com/article/us-phillips-66-results/phillips-66-profit-beats-on-higher-fuel-margins-shares-jump-idUSKBN1X41DX-oag360

Source: Reuters/Rick Wilking

The business, marketing & specialties, was helped by an 18% drop in crude prices in the third quarter that reduced the cost of the refined products like gasoline and aviation fuel.

“The beat was driven by stronger-than-expected results across all segments, but marketing & specialties particularly exceeded our expectations,” Morgan Stanley analysts wrote in a note.

Marketing fuel margins of $2.11 per barrel in the United States and $6.37 per barrel internationally was about 30-60% higher than the brokerage’s estimates.

Adjusted earnings in the unit rose nearly 30% to $498 million in the third quarter.

Profit in its midstream segment, which transports and stores crude, natural gas liquids (NGL) and exports liquefied petroleum gas, jumped more than 40% on the back of higher pipeline volumes and hydrocarbon trading.

Houston-based Phillips 66 has been beefing up its midstream assets, expanding its U.S. Gulf Coast NGL market hub, as well as adding storage capacity at Texas-based Clemens Caverns facility and Beaumont Terminal.

However, adjusted earnings at its largest refining segment slumped nearly 34% due to higher turnaround costs and as margins fell 16% to $11.18 per barrel.

The company’s refineries had worldwide crude oil capacity utilization rate of 97% during the quarter, compared with 93% a year earlier.

Net earnings more than halved to $712 million, or $1.58 per share, in the three months to Sept. 30.

Excluding a $690 million impairment related to investments in DCP Midstream LP, the company earned $3.11 per share, beating estimates of $2.59, according to IBES data from Refinitiv.

Smaller rival Valero Energy beat profit estimates on Thursday, thanks to cheap light crude from the prolific U.S. shale oil basins.

“Refining earnings are off to a very strong start with both PSX and VLO beating Street estimates and we expect other refiners especially Marathon Petroleum Corp and HollyFrontier Corp to follow with solid beats,” Credit Suisse analyst Manav Gupta said in a note.

Shares of Phillips 66 were trading up 4% at $115 in early trading. They have gained more than 28% this year to Thursday’s close.

October 18, 2019

Source: Houston Chronicle

The world’s largest oil field service company beat Wall Street expectations on revenue but got stung by pretax charges that resulted in a multibillion loss for stockholders during the third quarter.

Schlumberger posts $11.4 billion loss amid hefty pretax charges - oil and gas 360

Photo: Mayra Beltran

Schlumberger reported a $11.4 billion loss on $8.54 billion of revenue during the third quarter, which translated into a loss per share of $8.22 for common stockholders. The figures were mixed compared to Wall Street expectations of $8.5 billion in revenue and earnings per share of 40 cents.

The company’s third quarter figures were mixed compared to the $659 million of net income, $8 billion of revenue and earnings per share of 47 cents during the third quarter of 2018.

Schlumberger attributed the third quarter loss to $12.7 billion of pretax charges for the impairment of goodwill, intangible assets and fixed assets. Out of those figures, $8.8 billion were attributed to company-wide goodwill charges while another $1.6 billion was specifically attributed to the company’s North American hydraulic fracturing business.

Without those charges, the company made earnings per share of 43 cents — beating Wall Street expectations of 40 cents per share. In a statement, Schlumberger CEO Olivier Le Peuch focused on the year-over-year revenue growth but acknowledged challenges in the North American market.

“Sustained international activity drove overall growth despite mixed results in North America,” Le Peuch said. “The North America business saw strong offshore sales with minimal growth on land due to slowing activity and further pricing weakness.”

Headquartered in Paris with its principal offices in Houston, Schlumberger is the largest oilfield service company in the world with more than 100,000 employees in 85 nations.

The company posted a $2.2 billion profit on $32.8 billion of revenue in 2018.

July 18, 2019

By Aaron Vandeford, Managing Director, EnerCom

EnerCom, Inc. has compiled Second quarter earnings per share, revenue, EBITDA and cash flow per share analyst consensus estimates on 95 E&P and 73 Oilfield Service companies in the EnerCom database.

Download EnerCom’s full chart of estimates.

Listen to Q2 earnings calls.

The median E&P company earnings estimate for the quarter ending June 30, 2019, is $0.12 per share compared to actual earnings per share of ($0.03) and $0.33 for Q1’19 and Q4’18, respectively.

The median OilServices company earnings estimate for the quarter ending June 30, 2019, is ($0.03) per share compared to a loss per share of ($0.01) and ($0.11), for Q1’19 and Q4’18, respectively.

 

Energy Commodities

Crude Oil

U.S. crude oil production and lease condensate reached another milestone in April 2019, totaling 12.2 MMBOPD. April 2019 marks the first time that monthly U.S. crude oil production levels surpassed 12 MMBOPD, and this milestone comes less than a year after U.S. crude oil production surpassed 11 MMBOPD August 2018.

At a July 1, 2019 press conference following OPEC’s annual meeting in Vienna, Saudi Arabia’s Minister of Energy, Industry and Mineral Resources Khalid Al-Falih, also the chairman of the Joint Ministerial Monitoring Committee of OPEC+ (OPEC plus non-OPEC countries), said the OPEC+ group had agreed to continue production curtailments for up to nine more months (click here to read more).

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above picture to view EnerCom’s interactive dashboard

The average spot price for WTI in Q2 2019 was $59.92 per barrel, up 9.3% from the prior quarter and down 11.6% from the same quarter last year. The five-year strip at July 16, 2019 was $55.50 per barrel.

The median analyst estimate in mid-July for 2019 NYMEX oil was $60.50 per barrel with a high of $69.82 and a low of $55.50 per barrel.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Source: EnerCom Analytics

 

Natural Gas

For April 2019, total natural gas consumption was 72.8 Bcf/d, down 6.6% from the same month last year. Total natural gas production in April 2019 was 109.9 Bcf/d, up 11.4% from the same month last year.

Net injections to working gas totaled 81 Bcf for the week ending July 5. Working natural gas stocks are 2,471 Bcf, which is 13% more than the year-ago level and 5% lower than the five-year average for this week.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above image to view EnerCom’s interactive inventories dashboards

As production of American natural gas has increased, so has exports, leading to the U.S. becoming a net exporter of natural gas in 2017. In 2018, that trend continued, with the U.S. exporting a record of approximately 4 Tcf, while only importing 3 Tcf, the lowest figure since 2015 (click here to read more).

The average spot price for Henry Hub in Q2 2019 was $2.52 per MMBtu, 12.2% lower than the previous quarter and 9.3% higher than the same quarter last year. The five-year strip at July 16, 2019 was $2.65 per MMBtu.

The median analyst estimate in mid-July for 2019 NYMEX Henry Hub was $2.83 per MMBtu with a high of $3.40 and a low of $2.50 per MMBtu.

Bam! - It’s Earnings Season Again - Oil & Gas 360

Source: EnerCom Analytics

 

Rig Count – U.S. Rig Count

The U.S. rig count stood at 958 for the week ended July 12, 2019, down five from the week before and down 96 from the same week last year.

For the week ended July 12, 2019, there were 831 horizontal rigs active in the United States, a decrease of 99 from the same week a year ago. By play and as compared to the same week last year, rig count changes for the week ended July 12, 2019, include Haynesville (+3 rigs), Woodford Shale (-23 rigs), Marcellus (+6 rigs), Williston Basin (-2 rigs), Eagle Ford Shale (-15 rigs), DJ Niobrara (+2 rigs) and Permian Basin (-39 rigs).

Bam! - It’s Earnings Season Again - Oil & Gas 360

Click the above image to access EnerCom’s interactive rig count dashboard

 

 

Expected Themes for Conference Calls

Below are some themes and thoughts we expect to take prominence on the 2019 Q2 conference calls.

E&P Companies:

  • Free cash flow – When can you get there and what will you do with it
  • Potential for M&A activity
  • Well spacing and parent-child issues
  • Oil, gas takeaway capacity
  • Breakevens
  • Differentials
  • Full cycle returns
  • Liquidity, capital market funding and debt maturities
  • Hedge positions
  • Operating efficiencies

 

OilService companies:

  • Margin trends
  • Pricing trends
  • Service cost inflation
  • Infrastructure buildout and bottlenecks (particularly water and sand)
  • Oilfield service equipment utilization rates and the potential for added capacity
  • Global economic outlook
  • S. vs international activity
  • Potential impacts of sanctions and changing trade relationships
  • Maintenance needs

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.

 

 

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