EXHIBIT 10.1
Execution Version
NINTH AMENDMENT
TO
THIRD AMENDED AND RESTATED CREDIT AGREEMENT
DATED AS OF MAY 4, 2017
AMONG
NORTHERN OIL AND GAS, INC.,
as Borrower
,
ROYAL BANK OF CANADA,
as Administrative Agent,
AND
THE LENDERS PARTY HERETO
NINTH AMENDMENT TO
THIRD AMENDED AND RESTATED CREDIT AGREEMENT
This
NINTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT
(this “
Amendment
”), dated as of May 4, 2017 (the “
Ninth Amendment Effective Date
”), is by and among Northern Oil and Gas, Inc., a Minnesota corporation (the “
Borrower
”), Royal Bank of Canada (the “
Administrative Agent
”), and the Lenders party hereto.
R E C I T A L S
:
WHEREAS
, the Borrower, the Administrative Agent and the other Lenders party thereto entered into that certain Third Amended and Restated Credit Agreement, dated as of February 28, 2012 (as previously amended by the First Amendment dated as of June 29, 2012, the Second Amendment dated as of September 28, 2012, the Third Amendment dated as of March 28, 2013, the Fourth Amendment dated as of September 30, 2013, the Fifth Amendment dated as of April 7, 2015, the Sixth Amendment dated as of May 13, 2015, the Seventh Amendment dated as of October 21, 2015 and the Eighth Amendment dated as of May 6, 2016, as the same may be further amended, modified, supplemented or restated from time to time, the “
Credit Agreement
”);
WHEREAS
, the Borrower has requested that the Administrative Agent and the Lenders amend the Credit Agreement as set forth below; and
WHEREAS,
the Lenders have agreed to redetermine the Borrowing Base, which redetermination of the Borrowing Base shall constitute the Scheduled Redetermination for April 1, 2017.
WHEREAS
,
the Administrative Agent and the Lenders are willing to (i) amend the Credit Agreement and (ii) take such other actions as provided herein.
NOW, THEREFORE
, in consideration of the premises and the mutual covenants contained herein and in the Credit Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby agree as follows:
ARTICLE I
Definitions
Each capitalized term used in this Amendment and not defined herein shall have the meaning assigned to such term in the Credit Agreement.
ARTICLE II
Amendments to Credit Agreement
Section 2.01
Amendment to Definition of “Change in Control”
. The definition of “Change in Control” in Section 1.02 of the Credit Agreement is hereby amended by deleting “35%” and inserting in lieu thereof “50%”.
Section 2.02
Amendment to Section 9.01 of the Credit Agreement
. Section 9.01(c) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:
“(c)
Ratio of EBITDAX to Interest
. The Borrower will not permit its ratio of EBITDAX to interest expense (determined in accordance with GAAP) for the four fiscal quarters then ended (i) as of the last day of the fiscal quarters ending on or after March 31, 2016 but prior to December 31, 2016, to be less than 2.5 to 1.00, (ii) as of the last day of the fiscal quarter ending on December 31, 2016, to be less than 1.75 to 1.00, (iii) as of the last day of the fiscal quarters ending on or after March 31, 2017 but prior to June 30, 2018, to be less than 1.50 to 1.00 and (iv) as of the last day of the fiscal quarters ending on or after June 30, 2018, to be less than 1.75 to 1.00;
provided
however, if, in accordance with GAAP, the Borrower realizes any non-cash charges categorized as interest expense (including any such charges resulting from the accelerated realization of amortizing fees paid to the Administrative Agent or any Lender in connection with this Agreement in any given fiscal quarter as a result of a Borrowing Base reduction), then such non-cash charges shall be excluded from the calculation of interest expense for purposes of this
Section 9.01(c)
.”
Section 2.03
Amendment and Restatement of Section 9.04 of the Credit Agreement
. Section 9.04 of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:
“Section 9.04
Dividends and Distributions
. The Borrower will not, and will not permit any of its Subsidiaries to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its stockholders, make any distribution of its Property to its Equity Interest holders or Redeem Debt permitted under
Section 9.02(f)
or
Section 9.02(g)
, except (a) the Borrower may declare and pay dividends with respect to its Equity Interests payable solely in additional shares of its Equity Interests (other than Disqualified Capital Stock), (b) Subsidiaries may declare and pay dividends and make distributions to the Borrower with respect to their Equity Interests, (c) the Borrower may make Restricted Payments pursuant to and in accordance with stock option plans or other benefit plans for management or employees of the Credit Parties, (d) the Borrower may make Restricted Payments and Redeem Debt permitted under
Section 9.02(f)
or
Section 9.02(g)
in an amount not to exceed, in the aggregate for all Restricted Payments and Redemptions under this subsection (d), $10,000,000 and (e) the Borrower and any of its Subsidiaries may voluntarily Redeem (including pursuant to an exchange) (i) Debt permitted under
Section 9.02(f)
with the proceeds of any Permitted Refinancing permitted thereunder, (ii) Debt permitted under
Section 9.02(g)
with the proceeds of any Permitted Additional Debt permitted thereunder, (iii) Debt permitted under
Section 9.02(f)
or
Section 9.02(g)
with the issuance of additional Equity Interests (other than Disqualified Capital Stock) of the Borrower in exchange for all or a portion of such Debt and (iv) Debt permitted under
Section 9.02(f)
or
Section 9.02(g)
with cash proceeds of an offering of Equity Interests (other than Disqualified Capital Stock) of the Borrower so long as, in the case of this clause (iv), (A) no Default or Borrowing Base Deficiency has occurred and is continuing both before and after giving effect to such Redemption and such Redemption occurs substantially contemporaneously therewith, and in any event within three (3) Business Days following,
the receipt by the Borrower of cash proceeds in respect of such offering and (B) the Borrower is in (1) compliance with
Section 9.01(a)
as of the end of the most recently ended fiscal quarter (calculated on a pro forma basis after giving effect to such Redemption), (2) compliance with
Section 9.01(b)
as of the end of the most recently ended fiscal quarter (calculated on a pro forma basis after giving effect to such Redemption) and (3) compliance with
Section 9.01(c)
as of the end of the most recently ended four fiscal quarter period (calculated on a pro forma basis after giving effect to such Redemption).
ARTICLE III
Borrowing Base
Section 3.01
Redetermination of the Borrowing Base
. Effective as of the Ninth Amendment Effective Date, the amount of the Borrowing Base shall be reduced to $325,000,000.00, subject to further adjustments from time to time pursuant to Section 2.07, Section 8.13(c) or Section 9.12(d) of the Credit Agreement. The redetermination of the Borrowing Base pursuant to this
Section 3.01
shall constitute the Scheduled Redetermination for April 1, 2017.
ARTICLE IV
Conditions Precedent
This Amendment shall become effective as of the date first referenced above when and only when the following conditions are satisfied :
(a)
the Administrative Agent shall have received duly executed counterparts of this Amendment from the Borrower and the Lenders constituting at least the Required Lenders, in such numbers as the Administrative Agent or its counsel may reasonably request;
(b)
the Administrative Agent shall have received, for the account of each of the Lenders party to this Amendment (including, without limitation, Royal Bank of Canada), an Amendment Fee for each such Lender equal to 10.0 basis points (.10%) on the amount of such Lender’s Commitment (after giving effect to the reduction of the Borrowing Base set forth in
Section 3.01
).
(c)
at the time of and immediately after giving effect to this Amendment, no Default has occurred and is continuing;
(d)
at the time of and immediately after giving effect to this Amendment, the representations and warranties of the Credit Parties set forth in the Credit Agreement and in the other Loan Documents are true and correct, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties are true and correct as of such specified earlier date;
(e)
the Administrative Agent and the Lenders shall have received all fees due and payable on or prior to the effectiveness hereof as provided in any Loan Document, including reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement (including, without limitation, the reasonable fees and expenses of counsel to the Administrative Agent).
ARTICLE V
Representations and Warranties
The Borrower hereby represents and warrants to the Administrative Agent and each Lender that:
(a) Each of the representations and warranties made by the Borrower under the Credit Agreement and each other Loan Document is true and correct on and as of the actual date of execution of this Amendment by the Borrower, as if made on and as of such date, except for any representations and warranties made as of a specified date, which are true and correct as of such specified date.
(b) At the time of, and immediately after giving effect to, this Amendment, no Default has occurred and is continuing.
(c) The execution, delivery and performance by the Borrower of this Amendment have been duly authorized by the Borrower.
(d) This Amendment constitutes the legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(e) The execution, delivery and performance by the Borrower of this Amendment (i) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including the members or any class of directors of the Borrower or any other Person, whether interested or disinterested), nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of any Loan Document or the consummation of the transactions contemplated thereby, except (a) such as have been obtained or made and are in full force and effect, and (b) the Borrower may need to file a current report on Form 8‑K with the SEC disclosing this Amendment, (ii) will not violate any applicable law or regulation or the charter, by-laws or other organizational documents of the Borrower or any of its Subsidiaries or any order of any Governmental Authority, (iii) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any of its Subsidiaries or their Properties, or give rise to a right thereunder to require any payment to be made by the Borrower or such Subsidiary and (iv) will not result in the creation or imposition of any Lien on any Property of the Borrower or any of its Subsidiaries (other than the Liens created by the Loan Documents).
ARTICLE VI
Miscellaneous
Section 6.01
Credit Agreement in Full Force and Effect as Amended
. Except as specifically amended hereby, the Credit Agreement and other Loan Documents shall remain in full force and effect and are hereby ratified and confirmed as so amended. Except as expressly set forth herein, this Amendment shall not be deemed to be a waiver, amendment or modification of any provisions of the Credit Agreement or any other Loan Document or any right, power or remedy of the Administrative Agent or the Lenders, or constitute a waiver of any provision of the Credit Agreement or any other Loan Document, or any other document, instrument and/or agreement executed or delivered in connection therewith or of any Default or Event of Default under any of the foregoing, in each case whether arising before or after the date hereof or as a result of performance hereunder or thereunder. This Amendment also shall not preclude the future exercise of any right, remedy, power, or privilege available to the Administrative Agent and/or the Lenders whether under the Credit Agreement, the other Loan Documents, at law or otherwise. All references to the Credit Agreement shall be deemed to mean the Credit Agreement as modified hereby. The parties hereto agree to be bound by the terms and conditions of the Credit Agreement and Loan Documents as amended by this Amendment, as though such terms and conditions were set forth herein. Each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein” or words of similar import shall mean and be a reference to the Credit Agreement as amended by this Amendment, and each reference herein or in any other Loan Documents to the “Credit Agreement” shall mean and be a reference to the Credit Agreement as amended and modified by this Amendment.
Section 6.02
Governing Law
.
THIS AMENDMENT, AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER, SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAWS OF THE STATE OF NEW YORK.
Section 6.03
Descriptive Headings, Etc
. The descriptive headings of the sections of this Amendment are inserted for convenience only and shall not be deemed to affect the meaning or construction of any of the provisions hereof. The statements made and the terms defined in the recitals to this Amendment are hereby incorporated into this Amendment in their entirety.
Section 6.04
Entire Agreement
. This Amendment and the documents referred to herein represent the entire understanding of the parties hereto regarding the subject matter hereof and supersede all prior and contemporaneous oral and written agreements of the parties hereto with respect to the subject matter hereof.
Section 6.05
Loan Document
. This Amendment is a Loan Document executed under the Credit Agreement, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto.
Section 6.06
Counterparts
. This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which shall constitute an original but all of which when taken together shall constitute but one agreement. Delivery of an executed counterpart of the signature page of this Amendment by facsimile or other electronic transmission shall be effective as delivery of a manually executed counterpart thereof.
Section 6.07
Successors
. The execution and delivery of this Amendment by any Lender shall be binding upon each of its successors and assigns.
(Signature Pages Follow)
IN WITNESS WHEREOF
, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the date first written above.
NORTHERN OIL AND GAS, INC.
, as the Borrower
By:
/s/ Thomas Stoelk
Name: Thomas Stoelk
Title: Interim CEO & CFO
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
ROYAL BANK OF CANADA
, as Administrative Agent
By:
/s/ Rodica Dutka
Name: Rodica Dutka
Title: Manager, Agency
ROYAL BANK OF CANADA
, as a Lender
By:
/s/ Don J. McKinnerney
Name: Don J. McKinnerney
Title: Authorized Signatory
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
SUNTRUST BANK
, as a Lender
By:
/s/ William S. Krueger
Name: William S. Krueger
Title: First Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
BMO HARRIS FINANCING, INC.
, as a Lender
By:
/s/ James V. Ducote
Name: James V. Ducote
Title: Managing Director
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
KEYBANK NATIONAL ASSOCIATION
, as a Lender
By:
/s/ John Dravenstott
Name: John Dravenstott
Title: Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
SANTANDER BANK, N.A.
, as a Lender
By:
/s/ David O’Driscoll
Name: David O’Driscoll
Title: Senior Vice President
By:
/s/ Mark Connelly
Name: Mark Connelly
Title: Senior Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
CAPITAL ONE, NATIONAL ASSOCIATION
, as a Lender
By:
/s/ Mark Brewster
Name: Mark Brewster
Title: Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
BOKF, NA dba BANK OF OKLAHOMA
, as a Lender
By:
/s/ Benjamin H. Adler
Name: Benjamin H. Adler
Title: Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
BRANCH BANKING & TRUST COMPANY
, as a Lender
By:
/s/ Greg Krablin
Name: Greg Krablin
Title: Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
CADENCE BANK, N.A.
, as a Lender
By:
/s/ Kyle Gruen
Name: Kyle Gruen
Title: Assistant Vice President
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
ING CAPITAL LLC
, as a Lender
By:
/s/ Josh Strong
Name: Josh Strong
Title: Director
By:
/s/ Charles Hall
Name: Charles Hall
Title: Managing Director
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
FIFTH THIRD BANK
, as a Lender
By:
/s/ Thomas Kleiderer
Name: Thomas Kleiderer
Title: Director
SIGNATURE PAGE
NINTH AMENDMENT TO CREDIT AGREEMENT
Exhibit 99.1
Northern Oil and Gas, Inc. Announces 2017 First Quarter Results and Borrowing Base Redetermination under Revolving Credit Facility
MINNETONKA, MINNESOTA - May 8, 2017 - Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced
2017
first quarter results and completion of the semi-annual borrowing base redetermination under Northern’s revolving credit facility.
HIGHLIGHTS
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•
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Production totaled 1,196,924 barrels of oil equivalent (“Boe”) for the first quarter, averaging 13,299 Boe per day.
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•
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Northern’s first quarter 2017 producing well additions have a 30 day initial production average of 1,485 Boe per day, a 34% increase over the 2016 additions.
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•
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Northern’s 2016 producing well additions are tracking a 1 million Boe average type curve, a 59% increase over the 2015 additions.
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•
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Northern has participated in 27 gross wells since the beginning of 2016 with completions that used at least 10 million pounds of proppant; these wells are tracking a 1.2 million Boe average type curve.
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•
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Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325 million. Based on this new borrowing base, Northern had available liquidity of $196.5 million as of March 31, 2017.
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Northern’s GAAP net income for the
first
quarter of 2017 was
$16.9 million
. Adjusted net income for the quarter was a loss of
$0.1 million
. Adjusted EBITDA for the quarter was
$29.6 million
. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“Northern’s ability to allocate our capital expenditures to the highest return wells is allowing us to maintain production levels despite our dramatic reduction in capital expenditures since 2015,” commented Northern’s Interim CEO and CFO, Tom Stoelk. “Increased well productivity is being aided by the enhanced completion designs, which is improving returns as we execute on our capital allocation focused business plan. As the weather improves, an increase in completions is expected to drive production growth during the second half of 2017.”
GUIDANCE
Northern continues to expect 2017 total annual production to equal or modestly exceed 2016 total production. Northern expects that it will add approximately 12 net wells to production during the year, based on a preliminary capital budget of $102.2 million (including acreage and development capital). Net well additions will be weighted to the second half of 2017, which should result in sequential production growth in the third and fourth quarters. Management’s current expectations for 2017 operating metrics are as follows:
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2017
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Operating Expenses:
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Production Expenses (per Boe)
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$9.00 - $9.30
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Production Taxes (% of Oil & Gas Sales)
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10%
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General and Administration Expense (per Boe)
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$3.00 - $3.50
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Average Differential to NYMEX WTI
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$7.00 - $9.00
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LIQUIDITY
At
March 31, 2017
, Northern had
$134.0 million
in outstanding borrowings under its revolving credit facility, a $
10 million
reduction from December 31, 2016. In May 2017, Northern completed the semi-annual redetermination under its revolving credit facility with the borrowing base established at $325 million. Based on this new borrowing base, Northern had available liquidity of $196.5 million as of March 31, 2017, composed of
$5.5 million
in cash and $191.0 million of revolving credit facility availability.
HEDGING
Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes Northern’s open crude oil derivative contracts scheduled to settle after
March 31, 2017
.
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Swaps
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Collars
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Contract Period
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Volume (Bbls)
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Weighted Average Price (per Bbl)
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Volume (Bbls)
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Weighted Average Floor - Ceiling Prices (per Bbl)
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2017:
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2Q
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631,000
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$51.75
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75,000
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$50.00 - $60.06
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3Q
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632,000
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$53.36
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75,000
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$50.00 - $60.06
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4Q
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632,000
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$53.36
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75,000
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$50.00 - $60.06
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2018:
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1Q
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450,000
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$53.67
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90,000
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$50.00 - $60.25
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2Q
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451,000
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$53.67
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90,000
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$50.00 - $60.25
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3Q
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452,000
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$53.68
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90,000
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$50.00 - $60.25
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4Q
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364,000
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$52.94
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90,000
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$50.00 - $60.25
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CAPITAL EXPENDITURES & DRILLING ACTIVITY
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Three Months Ended March 31, 2017
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Capital Expenditures Incurred:
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Drilling, Completion & Capitalized Workover Expense
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$26.5 million
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Acreage
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$0.4 million
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Other
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$0.4 million
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Net Wells Added to Production
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2.0
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Net Producing Wells (Period-End)
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214.6
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Net Wells in Process (Period-End)
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15.9
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Weighted Average AFE for In-Process Wells (Period-End)
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$7.3 million
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For the
first
quarter of 2017, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $6.6
million.
ACREAGE
As of
March 31, 2017
, Northern leased approximately
151,672
net acres targeting the Williston Basin Bakken and Three Forks formations. As of
March 31, 2017
, approximately 84% of Northern’s North Dakota acreage position, and approximately
82%
of Northern’s total acreage position was developed, held by production or held by operations.
FIRST QUARTER 2017 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
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Three Months Ended March 31,
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2017
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2016
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% Change
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Net Production:
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Oil (Bbl)
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1,014,095
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1,107,989
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(8
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)%
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Natural Gas and NGLs (Mcf)
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1,096,971
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751,424
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46
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%
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Total (Boe)
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1,196,924
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1,233,227
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(3
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)%
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Average Daily Production:
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Oil (Bbl)
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11,268
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12,176
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(7
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)%
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Natural Gas and NGLs (Mcf)
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12,189
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8,257
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48
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%
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Total (Boe)
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13,299
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13,552
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(2
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)%
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Net Sales:
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Oil Sales
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$
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44,339,147
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$
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27,263,496
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63
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%
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Natural Gas and NGL Sales
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4,509,075
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1,103,845
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308
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%
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Gain (Loss) on Derivative Instruments, Net
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16,960,883
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3,463,883
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390
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%
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Other Revenue
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7,742
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5,012
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54
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%
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Total Revenues
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65,816,847
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31,836,236
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107
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%
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Average Sales Prices:
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Oil (per Bbl)
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$
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43.72
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$
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24.61
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78
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%
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Effect of (Loss) Gain on Settled Derivatives on Average Price (per Bbl)
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(0.09
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)
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22.97
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—
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%
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Oil Net of Settled Derivatives (per Bbl)
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43.63
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47.58
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(8
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)%
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Natural Gas and NGLs (per Mcf)
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4.11
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1.47
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180
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%
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Realized Price on a Boe Basis Including all Realized Derivative Settlements
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40.73
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43.64
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(7
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)%
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Operating Expenses:
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Production Expenses
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$
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11,674,348
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$
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11,959,260
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(2
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)%
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Production Taxes
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4,461,265
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2,766,899
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61
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%
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General and Administrative Expense
|
3,608,943
|
|
|
4,337,402
|
|
|
(17
|
)%
|
|
Depletion, Depreciation, Amortization and Accretion
|
12,828,143
|
|
|
17,846,089
|
|
|
(28
|
)%
|
|
|
|
|
|
|
|
|
Costs and Expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
Production Expenses
|
$
|
9.75
|
|
|
$
|
9.70
|
|
|
1
|
%
|
|
Production Taxes
|
3.73
|
|
|
2.24
|
|
|
67
|
%
|
|
General and Administrative Expense
|
3.02
|
|
|
3.52
|
|
|
(14
|
)%
|
|
Depletion, Depreciation, Amortization and Accretion
|
10.72
|
|
|
14.47
|
|
|
(26
|
)%
|
|
Net Producing Wells at Period End
|
214.6
|
|
|
207.3
|
|
|
4
|
%
|
Oil and Natural Gas Sales
In the first
three
months of
2017
, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased
72%
as compared to the first
three
months of
2016
, driven by a
77%
increase in realized prices, excluding the effect of settled derivatives, which was partially offset by a
3%
decrease in production. The higher average realized price in the first
three
months of
2017
as compared to the same period in
2016
was principally driven by higher average NYMEX oil and natural gas prices and a lower oil price differential. Oil price differential during the first
three
months of
2017
was
$8.06
per barrel, as compared to
$9.02
per barrel in the first
three
months of
2016
.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net was a gain of
$17.0 million
in the first
three
months of
2017
, compared to a gain of
$3.5 million
in the first
three
months of
2016
. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period end.
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
2017
|
|
2016
|
|
Cash Received (Paid) on Derivatives
|
$
|
(95,659
|
)
|
|
$
|
25,446,900
|
|
|
Non-Cash Gain (Loss) on Derivatives
|
17,056,542
|
|
|
(21,983,017
|
)
|
|
Gain on Derivative Instruments, Net
|
$
|
16,960,883
|
|
|
$
|
3,463,883
|
|
The average NYMEX oil price for the first
three
months of
2017
was
$51.78
compared to
$33.63
for the first
three
months of
2016
. Northern’s average realized price (including all cash derivative settlements) in the first
three
months of
2017
was
$40.73
per Boe compared to
$43.64
per Boe in the first
three
months of
2016
. The gain (loss) on settled derivatives decreased the average realized price per Boe by
$0.08
in the first
three
months of
2017
and increased the average realized price per Boe by
$20.63
in the first
three
months of
2016
.
Production Expenses
Production expenses were
$11.7 million
in the first
three
months of
2017
compared to
$12.0 million
in the first
three
months of
2016
. On a per unit basis, production expenses increased to
$9.75
per Boe in the first
three
months of
2017
, compared to
$9.70
per Boe in the first
three
months of
2016
. This increase was due to a
3%
decline in production levels over which fixed costs are spread, partially offset by a reduction in the aggregate dollar amount of production expenses. On an absolute dollar basis, production expenses in the first
three
months of
2017
were
2%
lower when compared to the first
three
months of
2016
due primarily to lower contract labor and maintenance costs, which was partially offset by a
4%
increase in the total number of net producing wells.
Production Taxes
Production taxes were
$4.5 million
in the first
three
months of
2017
compared to
$2.8 million
in the first
three
months of
2016
. The increase is due to higher commodity prices, which substantially increased oil and natural gas sales in the first
three
months of
2017
as compared to the first
three
months of
2016
. As a percentage of oil and natural gas sales, production taxes were
9.1%
and
9.8%
in the first
three
months of
2017
and
2016
, respectively. This decrease in production tax rates is due to a change in sales mix. Production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales. Crude oil sales represented
91%
of oil and gas sales in the first
three
months of
2017
compared to
96%
in the first
three
months of
2016
.
General and Administrative Expense
General and administrative expense was
$3.6 million
in the first
three
months of
2017
compared to
$4.3 million
in the first
three
months of
2016
. The decrease was due to a $1.0 million reduction in compensation expenses, primarily driven by a decrease in incentive compensation and lower non-cash share-based compensation expense, partially offset by a $0.3 million increase in legal and other professional fees.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was
$12.8 million
in the first
three
months of
2017
compared to
$17.8 million
in the first
three
months of
2016
. Depletion expense, the largest component of DD&A, decreased by
$5.0 million
in the first
three
months of
2017
compared to the first
three
months of
2016
. The aggregate decrease in depletion expense was driven by a
26%
decrease in the depletion rate per Boe, as well as a
3%
decrease in production levels. On a per unit basis, depletion expense was
$10.58
per Boe in the first
three
months of
2017
compared to
$14.35
per Boe in the first
three
months of
2016
. The
2017
depletion rate per Boe was lower due to the impairment of oil and natural gas properties in
2016
, which lowered the depletable base. Depreciation, amortization and accretion was
$0.2 million
and
$0.1 million
in the first
three
months of
2017
and
2016
, respectively.
Impairment of Oil and Natural Gas Properties
No impairment of oil and natural gas properties was recorded in the first
three
months of
2017
. As a result of low prevailing commodity prices and their effect on the proved reserve values of our properties, Northern recorded a non-cash ceiling test impairment of
$104.3 million
for the first
three
months of
2016
. The impairment charge affected Northern’s reported net income in 2016 but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was
$16.3 million
for the first
three
months of
2017
compared to
$16.1 million
in the first
three
months of
2016
.
Income Tax Provision
During the first
three
months of
2017
and
2016
, no income tax expense (benefit) was recorded on the income (loss) before income taxes due to the valuation allowance placed on our net deferred tax asset.
Non-GAAP Financial Measures
Adjusted Net Income (Loss) for the
first
quarter of
2017
was a loss of
$0.1 million
(representing approximately
$0.00
per diluted share), compared to income of
$0.5 million
(representing approximately
$0.01
per diluted share) for the
first
quarter of
2016
. The decrease in Adjusted Net Income (Loss) is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels. Northern defines Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of oil and natural gas properties, net of tax, and (iii) write-off of debt issuance costs, net of tax.
Adjusted EBITDA for the
first
quarter of
2017
was
$29.6 million
, compared to Adjusted EBITDA of
$36.2 million
for the
first
quarter of
2016
. The decrease in Adjusted EBITDA is primarily due to lower realized commodity prices (after the effect of settled derivatives) and lower production levels. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share based compensation expense, (vi) write-off of debt issuance costs and (vii) impairment of oil and natural gas properties.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.
FIRST QUARTER 2017 EARNINGS RELEASE CONFERENCE CALL
In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Monday, May 8, 2017 at 10:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website,
www.northernoil.com
, or by phone as follows:
Dial-In Number
: (855) 638-5677 (US/Canada) and (262) 912-4762 (International)
Conference ID
: 14741485 - Northern Oil and Gas, Inc. First Quarter 2017 Conference Call
Replay Dial-In Number
: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code
: 14741485 - Replay will be available through May 15, 2017
UPCOMING CONFERENCE SCHEDULE
Louisiana Energy Conference - Al Petrie Advisors
May 30 - June 2, 2017, New Orleans, LA
2017 RBC Capital Markets’ Global Energy and Power Executive Conference
June 6 - 7, 2017, New York, NY
EnerCom’s The Oil & Gas Conference 22
August 13 - 17, 2017, Denver, CO
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana.
More information about Northern Oil and Gas, Inc. can be found at
www.NorthernOil.com
.
SAFE HARBOR
This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond Northern’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s properties, Northern’s ability to acquire additional development opportunities, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products, services and prices.
Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control.
CONTACT:
Brandon Elliott, CFA
Executive Vice President,
Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
SOURCE Northern Oil and Gas, Inc.
CONDENSED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED
MARCH 31, 2017
AND
2016
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
|
2017
|
|
2016
|
|
REVENUES
|
|
|
|
|
Oil and Gas Sales
|
$
|
48,848,222
|
|
|
$
|
28,367,341
|
|
|
Gain on Derivative Instruments, Net
|
16,960,883
|
|
|
3,463,883
|
|
|
Other Revenue
|
7,742
|
|
|
5,012
|
|
|
Total Revenues
|
65,816,847
|
|
|
31,836,236
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
Production Expenses
|
11,674,348
|
|
|
11,959,260
|
|
|
Production Taxes
|
4,461,265
|
|
|
2,766,899
|
|
|
General and Administrative Expenses
|
3,608,943
|
|
|
4,337,402
|
|
|
Depletion, Depreciation, Amortization and Accretion
|
12,828,143
|
|
|
17,846,089
|
|
|
Impairment of Oil and Natural Gas Properties
|
—
|
|
|
104,311,122
|
|
|
Total Expenses
|
32,572,699
|
|
|
141,220,772
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM OPERATIONS
|
33,244,148
|
|
|
(109,384,536
|
)
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
Interest Expense, Net of Capitalization
|
(16,303,805
|
)
|
|
(16,098,682
|
)
|
|
Write-off of Debt Issuance Costs
|
—
|
|
|
(1,089,507
|
)
|
|
Other Income
|
180
|
|
|
6,971
|
|
|
Total Other Income (Expense)
|
(16,303,625
|
)
|
|
(17,181,218
|
)
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES
|
16,940,523
|
|
|
(126,565,754
|
)
|
|
|
|
|
|
|
INCOME TAX BENEFIT
|
—
|
|
|
—
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
$
|
16,940,523
|
|
|
$
|
(126,565,754
|
)
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share – Basic
|
$
|
0.28
|
|
|
$
|
(2.08
|
)
|
|
Net Income (Loss) Per Common Share – Diluted
|
$
|
0.27
|
|
|
$
|
(2.08
|
)
|
|
Weighted Average Shares Outstanding – Basic
|
61,446,156
|
|
|
60,964,029
|
|
|
Weighted Average Shares Outstanding – Diluted
|
61,972,123
|
|
|
60,964,029
|
|
CONDENSED BALANCE SHEETS
MARCH 31, 2017
AND
DECEMBER 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017 (unaudited)
|
|
December 31, 2016
|
|
ASSETS
|
|
|
|
|
Current Assets:
|
|
|
|
|
Cash and Cash Equivalents
|
$
|
5,518,799
|
|
|
$
|
6,486,098
|
|
|
Accounts Receivable, Net
|
33,945,067
|
|
|
35,840,042
|
|
|
Advances to Operators
|
1,178,400
|
|
|
1,577,204
|
|
|
Prepaid and Other Expenses
|
2,472,317
|
|
|
1,584,129
|
|
|
Derivative Instruments
|
3,671,684
|
|
|
4,517
|
|
|
Income Tax Receivable
|
1,402,179
|
|
|
1,402,179
|
|
|
Total Current Assets
|
48,188,446
|
|
|
46,894,169
|
|
|
|
|
|
|
|
Property and Equipment:
|
|
|
|
|
|
|
Oil and Natural Gas Properties, Full Cost Method of Accounting
|
|
|
|
|
|
|
Proved
|
2,456,816,317
|
|
|
2,428,595,048
|
|
|
Unproved
|
1,704,682
|
|
|
2,623,802
|
|
|
Other Property and Equipment
|
977,349
|
|
|
977,349
|
|
|
Total Property and Equipment
|
2,459,498,348
|
|
|
2,432,196,199
|
|
|
Less – Accumulated Depreciation, Depletion and Impairment
|
(2,068,695,690
|
)
|
|
(2,055,987,766
|
)
|
|
Total Property and Equipment, Net
|
390,802,658
|
|
|
376,208,433
|
|
|
|
|
|
|
|
Derivative Instruments
|
2,058,303
|
|
|
—
|
|
|
Deferred Income Taxes (Note 9)
|
—
|
|
|
—
|
|
|
Other Noncurrent Assets, Net
|
8,195,320
|
|
|
8,430,359
|
|
|
|
|
|
|
|
Total Assets
|
$
|
449,244,727
|
|
|
$
|
431,532,961
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ DEFICIT
|
|
Current Liabilities:
|
|
|
|
|
|
|
Accounts Payable
|
$
|
64,204,150
|
|
|
$
|
56,146,847
|
|
|
Accrued Expenses
|
4,721,006
|
|
|
6,094,938
|
|
|
Accrued Interest
|
18,666,667
|
|
|
4,682,894
|
|
|
Derivative Instruments
|
408,822
|
|
|
10,001,564
|
|
|
Asset Retirement Obligations
|
586,821
|
|
|
517,423
|
|
|
Total Current Liabilities
|
88,587,466
|
|
|
77,443,666
|
|
|
|
|
|
|
|
Long-term Debt, Net
|
823,450,676
|
|
|
832,625,125
|
|
|
Derivative Instruments
|
—
|
|
|
1,738,329
|
|
|
Asset Retirement Obligations
|
7,145,410
|
|
|
6,990,877
|
|
|
Other Noncurrent Liabilities
|
151,473
|
|
|
156,632
|
|
|
|
|
|
|
|
Total Liabilities
|
$
|
919,335,025
|
|
|
$
|
918,954,629
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 8)
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS’ DEFICIT
|
|
|
|
|
|
|
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding
|
—
|
|
|
—
|
|
|
Common Stock, Par Value $.001; 142,500,000 Authorized (3/31/2017 – 63,382,575
Shares Outstanding and 12/31/2016 – 63,259,781 Shares Outstanding)
|
63,383
|
|
|
63,260
|
|
|
Additional Paid-In Capital
|
444,285,756
|
|
|
443,895,032
|
|
|
Retained Deficit
|
(914,439,437
|
)
|
|
(931,379,960
|
)
|
|
Total Stockholders’ Deficit
|
(470,090,298
|
)
|
|
(487,421,668
|
)
|
|
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT
|
$
|
449,244,727
|
|
|
$
|
431,532,961
|
|
Reconciliation of Adjusted Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2017
|
|
2016
|
|
Net Income (Loss)
|
$
|
16,940,523
|
|
|
$
|
(126,565,754
|
)
|
|
Add:
|
|
|
|
|
|
|
Impact of Selected Items:
|
|
|
|
|
|
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(17,056,542
|
)
|
|
21,983,017
|
|
|
Write-off of Debt Issuance Costs
|
—
|
|
|
1,089,507
|
|
|
Impairment of Oil and Natural Gas Properties
|
—
|
|
|
104,311,122
|
|
|
Selected Items, Before Income Taxes
|
(17,056,542
|
)
|
|
127,383,646
|
|
|
Income Tax of Selected Items
(1)
|
46,656
|
|
|
(272,729
|
)
|
|
Selected Items, Net of Income Taxes
|
(17,009,886
|
)
|
|
127,110,917
|
|
|
Adjusted Net Income (Loss)
|
$
|
(69,363
|
)
|
|
$
|
545,163
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding – Basic
|
61,446,156
|
|
|
60,964,029
|
|
|
Weighted Average Shares Outstanding – Diluted
|
61,972,123
|
|
|
61,543,796
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share – Basic
|
$
|
0.28
|
|
|
$
|
(2.08
|
)
|
|
Add:
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes
|
(0.28
|
)
|
|
2.09
|
|
|
Adjusted Net Income (Loss) Per Common Share – Basic
|
$
|
—
|
|
|
$
|
0.01
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share – Diluted
|
$
|
0.27
|
|
|
$
|
(2.06
|
)
|
|
Add:
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes
|
(0.27
|
)
|
|
2.07
|
|
|
Adjusted Net Income (Loss) Per Common Share – Diluted
|
$
|
—
|
|
|
$
|
0.01
|
|
|
|
|
|
|
______________
|
|
|
|
(1)
|
For the 2017 column, this represents a tax impact using an estimated tax rate of
38.3%
, which includes a
$6.5 million
adjustment for a reduction in valuation allowance for the
three
months ended
March 31, 2017
. For the 2016 column, this represents a tax impact using an estimated tax rate of
35.9%
, which includes a
$45.5 million
adjustment for a change in valuation allowance for the
three
months ended
March 31, 2016
.
|
Reconciliation of Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2017
|
|
2016
|
|
Net Income (Loss)
|
$
|
16,940,523
|
|
|
$
|
(126,565,754
|
)
|
|
Add:
|
|
|
|
|
|
|
Interest Expense
|
16,303,805
|
|
|
16,098,682
|
|
|
Income Tax Benefit
|
—
|
|
|
—
|
|
|
Depreciation, Depletion, Amortization and Accretion
|
12,828,143
|
|
|
17,846,089
|
|
|
Impairment of Oil and Natural Gas Properties
|
—
|
|
|
104,311,122
|
|
|
Non-Cash Share Based Compensation
|
622,622
|
|
|
1,391,793
|
|
|
Write-off of Debt Issuance Costs
|
—
|
|
|
1,089,507
|
|
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(17,056,542
|
)
|
|
21,983,017
|
|
|
Adjusted EBITDA
|
$
|
29,638,551
|
|
|
$
|
36,154,456
|
|