mcf_Form_8K_Taxonomy2018

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

 

 

FORM 8–K

 

CURRENT REPORT

 

PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

 

 

Date of Report (Date of Earliest Event Reported):  August 8, 2019

 

CONTANGO OIL & GAS COMPANY

(Exact Name of Registrant as Specified in Charter)

 

 

 

 

 

 

 

 

Delaware

(State or Other Jurisdiction of Incorporation)

001-16317

 (Commission File Number)

95-4079863

(IRS Employer Identification No.)

 

 

717 Texas Ave., Suite 2900, Houston Texas 77002

(Address of Principal Executive Offices)

 

(713) 236-7400

(Registrant’s telephone number, including area code)

 

_____________________________________________________________________________

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

 

[]  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[]  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[]  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 14d-2(b))

[]  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

 

Emerging growth company

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, Par Value $0.04 per share

MCF

NYSE American

 

 

 

 

Item 2.02        Results of Operations and Financial Condition.

 

On August 8, 2019, Contango Oil & Gas Company (the “Company”) issued a press release providing its financial results for the three and six months ended June 30, 2019. A copy of the press release is attached hereto as Exhibit 99.1.

As provided in General Instruction B.2. of Form 8-K, the information furnished pursuant to Item 2.02 in this report on Form 8-K (including the press release attached as Exhibit 99.1 incorporated by reference in this report) shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01        Financial Statements and Exhibits.

(d)                   Exhibits

Exhibit Number

 

Description

99.1

 

Press Release dated August 8, 2019

 

 

 

 

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized.

 

17

 

 

 

 

CONTANGO OIL & GAS COMPANY

 

 

 

Date: August 8, 2019

 

/s/ E. JOSEPH GRADY

 

 

E. Joseph Grady

 

 

Senior Vice President and

 

 

Chief Financial and Accounting Officer

 

mcf_EX99_1_Taxonomy2018

EXHIBIT 99.1

Contango oil & gas COMPANY

NEWS RELEASE

Contango Announces Second Quarter 2019 Financial Results and Provides Operational Update

 

AUGUST 8, 2019 – HOUSTON, TEXAS – Contango Oil & Gas Company (NYSE American: MCF) (“Contango” or the “Company”) announced today its financial results for the second quarter ended June 30, 2019 and provided an operational update. 

 

 

Second Quarter Highlights

 

·

Production of 2.9 Bcfe for the quarter, or 32.3 Mmcfe per day,  approximate mid-point of guidance

   

·

Net loss of $5.0 million and EBITDAX of $4.4 million for the quarter. Adjusted EBITDAX of $3.1 million for the quarter, or $4.1 million when excluding non-recurring items described herein

 

·

17% decrease in general and administrative (“G&A”) costs for the quarter, or a 35% decrease when excluding non-recurring items described herein

 

·

Drilled three wells in Pecos County, TX in the Southern Delaware Basin and a fourth well in July

 

·

Sequential completion operations commenced in July on two wells (including one previously drilled in 2018), and is expected to commence in September for the remaining three wells   

 

 

Management Commentary

 

Wilkie S. Colyer, the Company’s President and Chief Executive Officer, said “Our goal in the Southern Delaware Basin this year was to add five more wells to our production base, and we are well on our way to accomplishing that goal.  The Ripper State #2H, a Wolfcamp B well that we drilled in December 2018, was the first well to be completed this year and began flowback in late-July. During the first six months of the year, we drilled three new wells in the Southern Delaware Basin,  with a fourth well drilled in July, and recently began  sequential completion operations on those wells. Our capital program this year remains on track to add production and cash flow in the second half of 2019, with the majority coming online in the fourth quarter as we flow back our NE Bullseye wells. As previously disclosed, during this period of commodity price instability, we will limit our capital expenditures to those necessary to meet leasehold obligations and focus on keeping our leverage at a manageable level. We are also excited about a new casing program that we employed on our latest well, the Old Ironside #1H, which lowered our overall drilling cost by 15%.”

 

Mr. Colyer continued, “We continue to work with our existing lenders and other sources of capital regarding a refinancing or replacement of our existing credit facility  to provide additional liquidity to pursue bolt-on opportunities for growth in this price environment and for our capital expenditures. Concurrently, we continue to work with our financial advisor to assist us in evaluating strategic initiatives, including a satisfactory resolution of our need to refinance our credit facility, which matures on October 1, 2019.”        

 

 

Summary Second Quarter Financial Results

 

Net loss for the three months ended June 31, 2019 was $5.0 million, or $0.15 per basic and diluted share, compared to a net loss of $7.2 million, or $0.29 per basic and diluted share, for the prior year quarter. This improvement is mainly attributable to a pre-tax $2.1 million gain on derivatives, compared to a $2.6 million loss in the prior year quarter, partially offset by a $2.4 million decrease in operating margin (i.e. revenues less expenses, before other income/expense), due to lower production and lower commodity prices.  Average weighted shares outstanding were approximately 33.9 million and 24.9 million for the current and prior year quarters, respectively.    

 

The Company reported Adjusted EBITDAX, as defined below, of approximately $3.1 million for the three months ended June 30, 2019, compared to $7.4 million for the same period last year, a decrease attributable primarily to lower revenues and $1.0 million in special costs associated with our pursuit of strategic initiatives.  Recurring Adjusted EBITDAX (defined as Adjusted EBITDAX exclusive of non-recurring strategic advisory fees) was $4.1 million for the current quarter, compared to $7.4 million for the prior year quarter.  Cash flow for the current quarter was $2.1 million, or $0.06 per share, compared to $6.1 million, or $0.25 per share for the prior year quarter. 

 

Revenues for the current quarter were approximately $12.8 million compared to $18.4 million for the prior year quarter, a decrease attributable to lower production during the current quarter due to non-core asset sales, downtime associated with repair and maintenance of an offshore compressor and pipeline,  and the temporary suspension of our West Texas drilling program from October 2018 through the first quarter of 2019 due to the unstable price environment, coupled with an 8% decrease in both crude oil and natural gas prices and a 40% decrease in natural gas liquids prices.    

 

Production for the second quarter of 2019 was approximately 2.9 Bcfe, or 32.3 Mmcfe per day, approximately the mid-point of our previously provided guidance, compared to 42.4 Mmcfe per day for the second quarter of 2018.  This overall decrease was largely due to a 0.7 Bcf decrease in natural gas production attributable to non-core asset sales in 2018,  downtime associated with repair and maintenance of an offshore compressor and pipeline, and normal offshore field decline. Crude oil and natural gas liquids production also decreased during the second quarter of 2019 to approximately 2,400 barrels per day, compared to approximately 2,900 barrels per day in the prior year quarter, a decline attributable in large part to the non-core asset sales and the temporary suspension of our West Texas drilling program from October 2018 through the first quarter of 2019. Our production for the third quarter of 2019 is expected to be between 30 and 35 Mmcfed, or comparable to second quarter production as the commencement of production on the wells currently being completed in the Southern Delaware Basin is not expected to begin until the fourth quarter.  The percentage of production from higher-value oil and natural gas liquids increased from 41% in the prior year quarter to 45% in the current quarter.  As a result of our current plans to complete and bring to production five wells during the second half of the year, we expect overall quarterly production and the percentage of liquids production to show improvement during the fourth quarter. 

 

The weighted average equivalent sales price during the three months ended June 30, 2019 was $4.34 per Mcfe, compared to $4.79 per Mcfe for the same period last year, as we experienced an 8% decrease in both crude oil and natural gas prices and a 40% decrease in natural gas liquids prices.    

 

Operating expenses for the three months ended June 30, 2019 were approximately $5.7 million, compared to $6.5 million for the same period last year. Included in operating expenses are direct lease operating expenses, transportation and processing costs, workover expenses and production and ad valorem taxes. Operating expenses exclusive of production and ad valorem taxes were approximately $5.0 million, and within our previously provided guidance, for the current quarter, compared to approximately $5.6 million for the prior year quarter, a decrease primarily attributable to the non-core asset sales. Our guidance for operating expenses for the third quarter of 2019, exclusive of production and ad valorem taxes, is between $4.7 and $5.3 million.         

 

DD&A expense for the three months ended June 30, 2019 was $7.6 million, or $2.57 per Mcfe, compared to $9.5 million, or $2.46 per Mcfe, for the prior year quarter, a decrease attributable to lower production during the quarter. 

 

Impairment and abandonment expense was $1.2 million for the current quarter, including approximately $0.2 million related to the impairment of certain proved properties,  $0.4 million related to expiring leases and $0.6 million related to plug and abandonment expenses. 

 

Total G&A expenses were $4.5 million for the three months ended June 30, 2019, compared to $5.4 million for the prior year quarter.  Recurring G&A expenses (defined as G&A expenses exclusive of non-recurring strategic advisory fees of $1.0 million) were $3.5 million, or $1.18 per Mcfe for the current quarter, compared to $5.4 million, or $1.39 per Mcfe for the prior year quarter, an approximate 35% decline. The decrease relates primarily to $0.5 million in lower salaries and bonus expense during the current quarter due to a smaller administrative workforce and savings on office rent attained through a renewal of our corporate office lease.  Recurring cash G&A (defined as G&A expenses exclusive of non-cash stock-based compensation of $0.6 million and non-recurring strategic advisory fees of $1.0 million) were $2.9 million for the current quarter, and below our previously provided guidance, compared to $3.8 million for the prior year quarter.  For the third quarter of 2019, we have provided guidance of $3.0 to $3.5 million for cash general and administrative expenses, exclusive of non-recurring fees and costs. 

 

Gain from affiliates (i.e., Exaro Energy III) for the three months ended June 30, 2019 was approximately $0.4 million, compared to a loss of $0.5 million for the same period last year.  

 

Gain from sale of assets for the three months ended June 30, 2019 was approximately $0.4 million, which related to post-closing adjustments from non-core property sales during 2018 and 2019, compared to $1.4 million for the same period last year, which was related to the sale of our non-operated assets in Starr County, Texas.

 

Gain on derivatives for the three months ended June 30, 2019 was approximately $2.1 million.  Of this amount, $0.5 million were realized gains while the remaining $1.6 million were non-cash, unrealized mark-to-market gains.  Loss on derivatives for the three months ended June 30, 2018 was approximately $2.6 million, of which $0.8 million were realized losses while the remaining $1.8 million were non-cash, unrealized mark-to-market losses.  

 

2019 Capital Program

 

Capital costs incurred for the three months ended June 30, 2019 were approximately $11.9 million, including $8.1 million for our drilling program in the Southern Delaware Basin in Pecos County, Texas.  Our capital expenditure forecast for 2019 is approximately $35.1 million, including $29.2 million in the Southern Delaware Basin.        

 

As of June 30, 2019, we had approximately $60 million of debt outstanding under our credit facility, with $13.1 million of availability, based on a borrowing base of $85 million, with an availability limit of $75 million, and we were in compliance with all but the Current Ratio covenant under our credit facility. We obtained a waiver for such non-compliance effective June 30, 2019.    The Seventh Amendment to our credit agreement also set the next borrowing base redetermination to August 1, 2019, which currently is in progress. 

 

Over the past several months, we have been in discussions with our current lenders and other sources of capital regarding a possible refinancing and/or replacement of our credit facility, which matures October 1, 2019.  These discussions have included a possible new or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures and acquisitions. There is no assurance,

however, that such discussions will result in a refinancing of the credit facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. While we expect to attain a favorable outcome on addressing the maturity date, these conditions raise substantial doubt about our ability to continue as a going concern.

 

Drilling Activity Update

 

Our recent Southern Delaware Basin activity consists of the following:

Ripper State #2H

The Ripper State #2H (49.6% WI, 37.2% NRI), targeting the Wolfcamp B formation and drilled in 2018 was recently completed and is currently flowing back.       

American Hornet #1H

The American Hornet #1H (49.9% WI, 39.6% NRI), targeting the Wolfcamp A formation, was spud in April 2019.  The well was drilled to a total measured depth of approximately 20,100 feet, including an approximate 9,800 foot lateral. Completion operations began in late-July 2019 and initial flowback is expected to begin later in the third quarter.  

Iron Snake #1H

The Iron Snake #1H (50% WI, 37.5% NRI), targeting the Wolfcamp B formation, was spud in March 2019.  The well was drilled to a total measured depth of approximately 20,500 feet, including an approximate 10,100 foot lateral. Completion operations are expected to begin in September, with initial flowback expected to begin in the fourth quarter.

Breakthrough State #1H

The Breakthrough State #1H (50% WI, 37.5% NRI), targeting the Wolfcamp A formation, was spud in June 2019. The well was drilled to a total measured depth of approximately 20,300 feet, including an approximate 9,800 foot lateral. Completion operations are expected to begin later this fall, with initial flowback expected to begin in the fourth quarter.

Old Ironside #1H

The Old Ironside #1H (49.7% WI, 37.3% NRI), targeting the Wolfcamp A formation, was spud in July 2019. The well was drilled to a total measured depth of approximately 20,400 feet, including an approximate 9,900 foot lateral.  Completion operations are expected to begin later this fall, with initial flowback expected to begin in the fourth quarter.

Derivative Instruments

As of June 30, 2019, we had the following financial derivative contracts in place with members of our bank group or third-party counterparties under an unsecured line of credit with no margin call provisions.  These contracts represent approximately 52% and 74% of our currently forecasted remaining 2019 natural gas and crude oil production from proved developed reserves (“PDP”),  respectively, as well as 58% and 68% of our currently forecasted 2020 PDP natural gas and crude oil production, respectively.

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Period

 

Derivative

 

Volume/Month

 

 

Price/Unit

Natural Gas

 

Jul-19

 

Swap

 

600,000 MMBtus

 

$

2.75 (1)

Natural Gas

 

Aug 2019 - Oct 2019

 

Swap

 

100,000 MMBtus

 

$

2.75 (1)

Natural Gas

 

Nov 2019 - Dec 2019

 

Swap

 

500,000 MMBtus

 

$

2.75 (1)

 

 

 

 

 

 

 

 

 

 

Oil

 

July 2019 - Dec 2019

 

Collar

 

7,000 Bbls

 

$

50.00 - 58.00 (2)

Oil

 

July 2019 - Dec 2019

 

Collar

 

4,000 Bbls

 

$

52.00 - 59.45 (3)

 

 

 

 

 

 

 

 

 

 

Oil

 

Jul-19

 

Swap

 

6,000 Bbls

 

$

66.10 (3)

 

 

 

 

 

 

 

 

 

 

Oil

 

July 2019

 

Swap

 

12,000 Bbls

 

$

72.10 (3)

Oil

 

Aug 2019 - Oct 2019

 

Swap

 

9,000 Bbls

 

$

72.10 (3)

Oil

 

Nov 2019 - Dec 2019

 

Swap

 

12,000 Bbls

 

$

72.10 (3)

 

 

 

 

 

 

 

 

 

 

Oil

 

July 2019 - Dec 2019

 

Swap

 

2,400 Bbls

 

$

61.72 (3)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

Jan 2020 - March 2020

 

Swap

 

425,000 MMBtus

 

$

2.84 (1)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

April 2020 - July 2020

 

Swap

 

400,000 MMBtus

 

$

2.53 (1)

Natural Gas

 

Aug 2020 - Oct 2020

 

Swap

 

40,000 MMBtus

 

$

2.53 (1)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

Nov 2020 - Dec 2020

 

Swap

 

375,000 MMBtus

 

$

2.70 (1)

 

 

 

 

 

 

 

 

 

 

Oil

 

Jan 2020 - June 2020

 

Swap

 

22,000 Bbls

 

$

57.74 (3)

Oil

 

July 2020 - Dec 2020

 

Swap

 

15,000 Bbls

 

$

57.74 (3)

 

(1)

Based on Henry Hub NYMEX natural gas prices.

(2)

Based on Argus Louisiana Light Sweet crude oil prices.

(3)

Based on West Texas Intermediate crude oil prices.

 

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI - Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was an $84 thousand loss as of June 30, 2019.

 

 

Selected Financial and Operating Data

The following table reflects certain comparative financial and operating data for the three and six months ended June 30, 2019 and 2018:    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six months ended

 

 

June 30, 

 

June 30, 

 

 

2019

 

2018

 

%

 

2019

 

2018

 

%

Offshore Volumes Sold:

    

 

 

    

 

 

    

 

 

 

 

    

 

 

    

 

Oil and condensate (Mbbls)

 

 

10

 

 

18

 

-44%

 

 

23

 

 

37

 

-38%

Natural gas (Mmcf)

 

 

1,325

 

 

1,695

 

-22%

 

 

2,960

 

 

3,991

 

-26%

Natural gas liquids (Mbbls)

 

 

58

 

 

59

 

-2%

 

 

124

 

 

137

 

-9%

Natural gas equivalents (Mmcfe)

 

 

1,736

 

 

2,156

 

-19%

 

 

3,847

 

 

5,033

 

-24%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore Volumes Sold:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (Mbbls)

 

 

117

 

 

133

 

-12%

 

 

230

 

 

255

 

-10%

Natural gas (Mmcf)

 

 

303

 

 

584

 

-48%

 

 

561

 

 

1,201

 

-53%

Natural gas liquids (Mbbls)

 

 

34

 

 

52

 

-35%

 

 

66

 

 

99

 

-33%

Natural gas equivalents (Mmcfe)

 

 

1,206

 

 

1,698

 

-29%

 

 

2,330

 

 

3,325

 

-30%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Volumes Sold:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (Mbbls)

 

 

127

 

 

151

 

-16%

 

 

253

 

 

292

 

-13%

Natural gas (Mmcf)

 

 

1,628

 

 

2,279

 

-29%

 

 

3,521

 

 

5,192

 

-32%

Natural gas liquids (Mbbls)

 

 

92

 

 

111

 

-17%

 

 

190

 

 

236

 

-19%

Natural gas equivalents (Mmcfe)

 

 

2,942

 

 

3,854

 

-24%

 

 

6,177

 

 

8,358

 

-26%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Daily Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (Mbbls)

 

 

1.4

 

 

1.7

 

-16%

 

 

1.4

 

 

1.6

 

-13%

Natural gas (Mmcf)

 

 

17.9

 

 

25.0

 

-29%

 

 

19.5

 

 

28.7

 

-32%

Natural gas liquids (Mbbls)

 

 

1.0

 

 

1.2

 

-17%

 

 

1.0

 

 

1.3

 

-19%

Natural gas equivalents (Mmcfe)

 

 

32.3

 

 

42.4

 

-24%

 

 

34.1

 

 

46.2

 

-26%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

58.42

 

$

63.53

 

-8%

 

$

54.78

 

$

63.16

 

-13%

Natural gas (per Mcf)

 

$

2.37

 

$

2.57

 

-8%

 

$

2.70

 

$

2.78

 

-3%

Natural gas liquids (per Bbl)

 

$

16.01

 

$

26.84

 

-40%

 

$

18.05

 

$

25.32

 

-29%

Total (per Mcfe)

 

$

4.34

 

$

4.79

 

-9%

 

$

4.33

 

$

4.65

 

-7%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30, 

 

June 30, 

 

 

2019

 

2018

 

%

   

2019

 

2018

 

%

Offshore Selected Costs ($ per Mcfe)

    

 

 

    

 

 

    

 

 

 

 

    

 

 

    

 

Lease operating expenses (1)

 

$

0.85

 

$

0.97

 

-12%

 

$

0.79

 

$

0.88

 

-10%

Production and ad valorem taxes

 

$

0.08

 

$

0.08

 

0%

 

$

0.08

 

$

0.07

 

14%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Onshore Selected Costs ($ per Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (1)

 

$

2.95

 

$

2.09

 

41%

 

$

2.92

 

$

2.21

 

32%

Production and ad valorem taxes

 

$

0.43

 

$

0.39

 

10%

 

$

0.32

 

$

0.38

 

-16%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Selected Costs ($ per Mcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (1)

 

$

1.72

 

$

1.46

 

18%

 

$

1.59

 

$

1.41

 

13%

Production and ad valorem taxes

 

$

0.22

 

$

0.22

 

0%

 

$

0.17

 

$

0.19

 

-11%

General and administrative expense (cash)

 

$

1.32

 

$

0.98

 

35%

 

$

1.27

 

$

1.09

 

17%

Interest expense

 

$

0.37

 

$

0.33

 

12%

 

$

0.35

 

$

0.32

 

9%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDAX (2) (thousands)

 

$

3,132

 

$

7,401

 

 

 

$

8,576

 

$

15,745

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Shares Outstanding (thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

33,909

 

 

24,933

 

 

 

 

33,840

 

 

24,863

 

 

Diluted

 

 

33,909

 

 

24,933

 

 

 

 

33,840

 

 

24,863

 

 

 


(1)

LOE includes transportation and workover expenses.

(2)

Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income.

 

CONTANGO OIL & GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

    

2019

    

2018

ASSETS

 

(unaudited)

Cash and cash equivalents

 

$

 —

 

$

 —

Accounts receivable, net

 

 

10,147

 

 

11,531

Other current assets

 

 

3,545

 

 

5,903

Net property and equipment

 

 

231,760

 

 

233,174

Investment in affiliates and other non-current assets

 

 

7,204

 

 

6,524

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

252,656

 

$

257,132

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

 

47,966

 

 

39,506

Current portion of long-term debt

 

 

60,000

 

 

60,000

Other current liabilities

 

 

1,118

 

 

1,751

Long-term debt

 

 

 —

 

 

 —

Asset retirement obligations

 

 

11,725

 

 

12,168

Other non-current liabilities

 

 

3,677

 

 

3,318

Total shareholders’ equity

 

 

128,170

 

 

140,389

 

 

 

 

 

 

 

TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY

 

$

252,656

 

$

257,132

 

 

 

 

 

 

 

CONTANGO OIL & GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30, 

 

June 30, 

 

    

2019

    

2018

    

2019

    

2018

 

 

(unaudited)

REVENUES

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate sales

 

$

7,439

 

$

9,607

 

$

13,845

 

$

18,418

Natural gas sales

 

 

3,857

 

 

5,848

 

 

9,499

 

 

14,457

Natural gas liquids sales

 

 

1,466

 

 

2,993

 

 

3,429

 

 

6,010

Total revenues

 

 

12,762

 

 

18,448

 

 

26,773

 

 

38,885

 

 

 

 

 

 

 

 

 

 

 

 

 

EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

5,694

 

 

6,478

 

 

10,886

 

 

13,405

Exploration expenses

 

 

249

 

 

394

 

 

473

 

 

863

Depreciation, depletion and amortization

 

 

7,573

 

 

9,498

 

 

15,129

 

 

19,983

Impairment and abandonment of oil and gas properties

 

 

1,247

 

 

777

 

 

1,834

 

 

4,104

General and administrative expenses

 

 

4,456

 

 

5,354

 

 

9,461

 

 

12,080

Total expenses

 

 

19,219

 

 

22,501

 

 

37,783

 

 

50,435

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

Gain (loss) from investment in affiliates, net of income taxes

 

 

427

 

 

(475)

 

 

457

 

 

232

Gain from sale of assets

 

 

421

 

 

1,370

 

 

409

 

 

10,817

Interest expense

 

 

(1,079)

 

 

(1,262)

 

 

(2,171)

 

 

(2,671)

Gain (loss) on derivatives, net

 

 

2,065

 

 

(2,610)

 

 

(813)

 

 

(3,642)

Other income

 

 

89

 

 

 3

 

 

 3

 

 

882

Total other income (expense)

 

 

1,923

 

 

(2,974)

 

 

(2,115)

 

 

5,618

 

 

 

 

 

 

 

 

 

 

 

 

 

NET LOSS BEFORE INCOME TAXES

 

 

(4,534)

 

 

(7,027)

 

 

(13,125)

 

 

(5,932)

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax provision

 

 

(427)

 

 

(151)

 

 

(454)

 

 

(309)

 

 

 

 

 

 

 

 

 

 

 

 

 

NET LOSS

 

$

(4,961)

 

$

(7,178)

 

$

(13,579)

 

$

(6,241)

 

Non-GAAP Financial Measures

 

This news release includes certain non-GAAP financial information as defined by Securities and Exchange Commission (“SEC”) rules. Pursuant to SEC requirements, reconciliations of non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP) are included in this press release.

 

Adjusted EBITDAX represents net income (loss) before interest expense, taxes, depreciation, depletion and amortization, and oil and gas exploration expenses (“EBITDAX”) as further adjusted to reflect the items set forth in the table below and is a measure required to be used in determining our compliance with financial covenants under our credit facility.  Recurring Adjusted EBITDAX represents Adjusted EBITDAX exclusive of non-recurring strategic advisory fees.

 

We have included Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreement.  We believe Adjusted EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and therefore highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures.  We also believe that securities analysts, investors and other interested parties frequently use Adjusted EBITDAX in the evaluation of companies, many of which present Adjusted EBITDAX when reporting their results.  Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreement.  We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX.  Non-compliance with the financial covenants contained in our credit agreement could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments.  Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use Adjusted EBITDAX to assess:

 

·

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

 

·

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

 

·

our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and

 

·

the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

 

 

The following table reconciles net income to EBITDAX and Adjusted EBITDAX for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30, 

 

June 30, 

 

    

2019

    

2018

    

2019

    

2018

 

 

(in thousands)

Net loss

 

$

(4,961)

 

$

(7,178)

 

$

(13,579)

 

$

(6,241)

Interest expense

 

 

1,079

 

 

1,262

 

 

2,171

 

 

2,671

Income tax provision

 

 

427

 

 

151

 

 

454

 

 

309

Depreciation, depletion and amortization

 

 

7,573

 

 

9,498

 

 

15,129

 

 

19,983

Exploration expense

 

 

249

 

 

394

 

 

473

 

 

863

EBITDAX

 

$

4,367

 

$

4,127

 

$

4,648

 

$

17,585

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized loss (gain) on derivative instruments

 

$

(1,568)

 

$

1,792

 

$

2,078

 

$

2,311

Non-cash stock-based compensation charges

 

 

585

 

 

1,584

 

 

1,637

 

 

3,008

Impairment of oil and gas properties

 

 

596

 

 

793

 

 

1,079

 

 

3,890

Gain on sale of assets and investment in affiliates

 

 

(848)

 

 

(895)

 

 

(866)

 

 

(11,049)

Adjusted EBITDAX

 

$

3,132

 

$

7,401

 

$

8,576

 

$

15,745

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-recurring strategic advisory fees

 

 

985

 

 

 —

 

 

1,736

 

 

 —

Recurring Adjusted EBITDAX

 

$

4,117

 

$

7,401

 

$

10,312

 

$

15,745

 

In addition to Adjusted EBITDAX, we may provide additional non-GAAP financial measures because our management believes providing investors with this information gives additional insights into our profitability, cash flows and expenses.

 

Adjusted EBITDAX and other non-GAAP measures in this release are not presentations made in accordance with generally accepted accounting principles, or GAAP.  As discussed above, we believe that the presentation of non-GAAP financial measures in this release is appropriate.  However, when evaluating our results, you should not consider the non-GAAP financial measures in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net loss. For example, Adjusted EBITDAX has  material limitations as a  performance measure because it excludes items that are necessary elements of our costs and operations.  Because other companies may calculate Adjusted EBITDAX differently than we do, Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

 

Guidance for Third Quarter 2019

The Company is providing the following guidance for the third calendar quarter of 2019.

 

 

 

 

Production

    

30,000 - 35,000 Mcfe per day

 

 

 

LOE (including transportation and workovers)

 

$4.7 million - $5.3 million

 

 

 

Production and ad valorem taxes (% of Revenue)

 

3.75% - 4.25%

 

 

 

Cash G&A

 

$3.5 million - $4.0 million

 

 

 

DD&A Rate

 

$2.40 - $2.65

 

 

Teleconference Call

Contango management will hold a conference call to discuss the information described in this press release on Friday, August 9, 2019 at 8:00  am Central Daylight Time.  Those interested in participating in the

earnings conference call may do so by calling 1-877-692-8955, (International 1-234-720-6979) and entering participation code 4251487.  A replay of the call will be available from Friday, August 9, 2019 at 11:00am CDT through Friday, August 16, 2019 at 11:55pm CDT by calling 1-866-207-1041, (International 1-402-970-0847) and entering participation code 1369794.

About Contango Oil & Gas Company

Contango Oil & Gas Company is a Houston, Texas based, independent oil and natural gas company whose business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the United States. Additional information is available on the Company's website at http://contango.com.  Information on our website is not part of this release.

 

Forward-Looking Statements and Cautionary Statements

 

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are, based on Contango’s current expectations and includes statements regarding our estimates of future production, and other guidance (including information regarding production, lease operating expenses, cash G&A expenses, and DD&A Rate), the Company’s drilling program and capital expenditures, a new casing program and expected reduction in overall drilling cost,  acquisitions and divestitures, future results of operations, the refinancing or replacement of the Company’s credit facility or other strategic initiatives, the quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance. Words and phrases used to identify our forward-looking statements include terms such as “guidance”, "expects", “projects”, "anticipates", “believes”, "plans", "estimates", "potential", "possible", "probable", or "intends", or words and phrases stating that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved. Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; our ability to comply with financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness, including our ability to refinance and/or replace our existing credit facility, provide additional liquidity for future capital expenditures and/or continue as a going concern; fluctuations in oil and gas prices; risks associated with derivative positions; our ability to realize expected value from acquisitions and to complete strategic dispositions of assets and realize the benefits of such dispositions; the need to take impairments on properties due to lower commodity prices; the limited trading volume of our common stock and general market volatility;  ability of our management team to execute its plans or to meet its goals; shortages of drilling equipment, oil field personnel and services; unavailability of gathering systems, pipelines and processing facilities; the possibility that government policies may change or governmental approvals may be delayed or withheld; and the other factors discussed under the “Risk Factors” heading in our annual report on Form 10-K for the year ended December 31, 2018 and our quarterly reports on Form 10-Q filed with or furnished to the SEC. Additional information on these and other factors which could affect Contango’s operations or financial results are included in Contango’s reports on file with the SEC. Investors are cautioned that any forward-

looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements speak only as of the date they were made and are based on the estimates and opinions of management at the time the statements are made. Contango does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. Initial production

rates of wells and initial indications of formation performance or the benefits of any transaction are not

necessarily indicative of future or long-term results.

 

 

 

 

Contact:

 

Contango Oil & Gas Company

 

E. Joseph Grady – 713-236-7400

Sergio Castro – 713-236-7400

Senior Vice President and Chief Financial Officer

Vice President and Treasurer