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EX-32.2 - EX-32.2 - Atlas Energy Group, LLCatls-ex322_6.htm
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EX-31.2 - EX-31.2 - Atlas Energy Group, LLCatls-ex312_9.htm
EX-31.1 - EX-31.1 - Atlas Energy Group, LLCatls-ex311_8.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2017

 

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from               to              

Commission file number: 001-36725

 

Atlas Energy Group, LLC

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

45-3741247

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

425 Houston Street, Suite 300

Fort Worth, TX

 

76102

(Address of principal executive offices)

 

(Zip code)

 

Registrant’s telephone number, including area code: (412) 489-0006

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes      No  

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  

 

Accelerated filer  

    

Non-accelerated filer  

 

Smaller reporting company  

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

As of May 11, 2017, there were 26,061,818 common units outstanding.

 

 

 


 

ATLAS ENERGY GROUP, LLC

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

TABLE OF CONTENTS

 

 

  

 

Page

PART 1. FINANCIAL INFORMATION

 

Item 1.

  

Financial Statements (Unaudited)

 

 

  

Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016

5

 

  

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2017 and 2016

6

 

  

Condensed Consolidated Statements of Comprehensive Loss for the Three Months Ended March 31, 2017 and 2016

7

 

  

Condensed Consolidated Statement of Changes in Unitholders’ Equity for the Three Months Ended March 31, 2017

8

 

  

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016

9

 

  

Notes to Condensed Consolidated Financial Statements

10

 

 

 

 

Item 2.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

25

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

37

Item 4.

  

Controls and Procedures

39

 

PART II. OTHER INFORMATION

 

Item 6.

  

Exhibits

39

 

SIGNATURES

40

 

 

 

 

 

 

 

 

2


 

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements.  These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology.  In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements.  We have based these forward-looking statements on our current expectations, assumptions, estimates and projections.  While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control.  These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.  Some of the key factors that could cause actual results to differ from our expectations include:

 

actions that we may take in connection with our liquidity needs, including the incurrence of amounts of cancellation of indebtedness income;

 

the fact that our cash flow is substantially dependent on the ability of Titan Energy, LLC (“Titan”) and Atlas Growth Partners, L.P. (“AGP”) to make distributions, but neither Titan nor AGP is currently paying distributions;

 

the demand for natural gas, oil, NGLs and condensate;

 

the price volatility of natural gas, oil, NGLs, and condensate

 

economic conditions and instability in the financial markets;

 

the impact of our common units being quoted on the OTCQX Market and not listed on a national securities exchange;

 

changes in the market price of our common units;

 

future financial and operating results;

 

economic conditions and instability in the financial markets;

 

success in efficiently developing and exploiting our reserves and economically finding or acquiring additional recoverable reserves and meeting substantial capital investment needs;

 

the accuracy of estimated natural gas and oil reserves;

 

the financial and accounting impact of hedging transactions;

 

potential changes in tax laws and environmental and other regulations that may affect our business;

 

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

 

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

 

impact fees and severance taxes;

 

the effects of intense competition in the natural gas and oil industry;

 

general market, labor and economic conditions and related uncertainties;

 

the ability to retain certain key employees and customers;

 

dependence on the gathering and transportation facilities of third parties;

 

the availability of drilling rigs, equipment and crews;

 

expirations of undeveloped leasehold acreage;

 

exposure to new and existing litigation; and

 

development of alternative energy resources.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under “Item 1A: Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.  Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements.  The forward-looking statements included in this report are made only as of the date hereof.  We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

3


 

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

4


 

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

 

 

 

March 31,

 

 

December 31,

 

 

 

2017

 

 

2016

 

ASSETS

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

11,916

 

 

$

12,009

 

Accounts receivable

 

 

789

 

 

 

835

 

Current derivative assets

 

 

132

 

 

 

 

Prepaid expenses and other

 

 

49

 

 

 

40

 

Total current assets

 

 

12,886

 

 

 

12,884

 

Property, plant and equipment, net

 

 

67,766

 

 

 

68,899

 

Long-term derivative assets

 

 

37

 

 

 

 

Other assets, net

 

 

21,578

 

 

 

23,293

 

Total assets

 

$

102,267

 

 

$

105,076

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND UNITHOLDERS’ EQUITY (DEFICIT)

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Accounts payable

 

 

687

 

 

 

890

 

Advances from affiliates

 

 

10,253

 

 

 

4,147

 

Current portion of derivative payable

 

 

 

 

 

284

 

Accrued interest

 

 

54

 

 

 

28

 

Accrued liabilities

 

 

5,793

 

 

 

12,050

 

Current portion of long-term debt

 

 

85,756

 

 

 

81,100

 

Total current liabilities

 

 

102,543

 

 

 

98,499

 

Long-term derivative liability

 

 

 

 

 

280

 

Asset retirement obligations and other

 

 

2,834

 

 

 

4,863

 

 

 

 

 

 

 

 

 

 

Commitments and contingencies (Note 8)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unitholders’ equity (deficit):

 

 

 

 

 

 

 

 

Common unitholders’ equity (deficit)

 

 

(121,596

)

 

 

(115,734

)

Series A preferred equity

 

 

46,747

 

 

 

45,148

 

Warrants

 

 

1,868

 

 

 

1,868

 

 

 

 

(72,981

)

 

 

(68,718

)

Non-controlling interests

 

 

69,871

 

 

 

70,152

 

Total unitholders’ equity (deficit)

 

 

(3,110

)

 

 

1,434

 

Total liabilities and unitholders’ equity (deficit)

 

$

102,267

 

 

$

105,076

 

 

See accompanying notes to condensed consolidated financial statements.

5


 

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

 

 

 

Three Months Ended

March 31,

 

 

2017

 

 

2016

 

Revenues:

 

 

 

 

 

 

 

 

Gas and oil production

 

$

2,396

 

 

$

51,593

 

ARP Drilling Partnerships management

 

 

 

 

 

8,482

 

Gain (loss) on mark-to-market derivatives

 

 

757

 

 

 

46,453

 

Other, net

 

 

722

 

 

 

334

 

Total revenues

 

 

3,875

 

 

 

106,862

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

Gas and oil production

 

 

952

 

 

 

36,656

 

ARP Drilling Partnerships management

 

 

 

 

 

6,283

 

General and administrative

 

 

1,785

 

 

 

21,920

 

Depreciation, depletion and amortization

 

 

1,112

 

 

 

34,272

 

Total costs and expenses

 

 

3,849

 

 

 

99,131

 

 

 

 

 

 

 

 

 

 

Operating income

 

 

26

 

 

 

7,731

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(4,929

)

 

 

(29,448

)

Gain on early extinguishment of debt, net

 

 

 

 

 

20,445

 

Net loss

 

 

(4,903

)

 

 

(1,272

)

Preferred unitholders’ dividends

 

 

 

 

 

(339

)

Net (income) loss attributable to non-controlling interests

 

 

281

 

 

 

(5,340

)

Net loss attributable to unitholders’ interests

 

$

(4,622

)

 

$

(6,951

)

 

 

 

 

 

 

 

 

 

Net loss attributable to unitholders per common unit (Note 2):

 

 

 

 

 

 

 

 

Basic and diluted

 

$

(0.18

)

 

$

(0.27

)

Weighted average common units outstanding (Note 2):

 

 

 

 

 

 

 

 

Basic and diluted

 

 

26,062

 

 

 

26,028

 

 

See accompanying notes to condensed consolidated financial statements.

6


 

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

 

 

Three Months Ended

March 31,

 

 

2017

 

 

2016

 

Net loss

 

$

(4,903

)

 

$

(1,272

)

Other comprehensive loss:

 

 

 

 

 

 

 

 

Derivative instruments designated as cash flow hedges:

 

 

 

 

 

 

 

 

Reclassification to mark-to-market gains

 

 

 

 

 

(3,515

)

Total other comprehensive loss

 

 

 

 

 

(3,515

)

Comprehensive loss

 

 

(4,903

)

 

 

(4,787

)

Comprehensive (income) loss attributable to non-controlling interests

 

 

281

 

 

 

(2,611

)

Comprehensive loss attributable to unitholders’ interest

 

$

(4,622

)

 

$

(7,398

)

 

See accompanying notes to condensed consolidated financial statements.

 

 

7


 

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN UNITHOLDERS’ EQUITY (DEFICIT)

(in thousands, except unit data)

(Unaudited)

 

 

 

Series A Preferred

Equity

 

Common Unitholders’

Equity (Deficit)

 

Owner’s

 

Warrants

 

Accumulated

Other

Comprehensive

 

Non-

Controlling

 

Total

Unitholders’

Equity

 

 

 

Units

 

 

Amount

 

Units

 

 

Amount

 

Equity

 

Units

 

 

Amount

 

Income

 

Interest

 

(Deficit)

 

Balance at December 31, 2016

 

 

1,805,858

 

 

$

45,148

 

 

26,044,592

 

 

$

(115,734

)

$

 

 

4,668,044

 

 

$

1,868

 

$

 

$

70,152

 

$

1,434

 

Issuance of units

 

 

63,945

 

 

 

1,599

 

 

 

 

 

(1,599

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net issued and unissued units under incentive plan

 

 

 

 

 

 

 

17,226

 

 

 

359

 

 

 

 

 

 

 

 

 

 

 

 

 

359

 

Net income (loss)

 

 

 

 

 

 

 

 

 

 

(4,622

)

 

 

 

 

 

 

 

 

 

 

(281

)

 

(4,903

)

Balance at March 31, 2017

 

 

1,869,803

 

 

$

46,747

 

 

26,061,818

 

 

$

(121,596

)

$

 

 

4,668,044

 

 

$

1,868

 

$

 

$

69,871

 

$

(3,110

)

 

See accompanying notes to condensed consolidated financial statements.

 

 

8


 

ATLAS ENERGY GROUP, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

Net loss

 

$

(4,903

)

 

$

(1,272

)

Adjustments to reconcile net loss to net cash used in operating activities:

 

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

1,112

 

 

 

34,272

 

Gain on early extinguishment of debts, net

 

 

 

 

 

(20,445

)

Gain on derivatives

 

 

(705

)

 

 

(40,428

)

Amortization of deferred financing costs and debt discount

 

 

374

 

 

 

4,365

 

Non-cash compensation expense

 

 

359

 

 

 

1,905

 

Paid-in-kind interest

 

 

4,303

 

 

 

 

Distributions paid to non-controlling interests

 

 

 

 

 

(9,447

)

Equity income in unconsolidated companies

 

 

(722

)

 

 

(220

)

Distributions received from unconsolidated companies

 

 

404

 

 

 

471

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable, prepaid expenses and other

 

 

6,102

 

 

 

67,447

 

Accounts payable and accrued liabilities

 

 

(6,409

)

 

 

(69,974

)

Net cash used in operating activities

 

 

(85

)

 

 

(33,326

)

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

 

 

Capital expenditures

 

 

 

 

 

(18,719

)

Other

 

 

 

 

 

1,634

 

Net cash used in investing activities

 

 

 

 

 

(17,085

)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

 

 

Repayments under term loan facilities

 

 

 

 

 

(4,250

)

Borrowings under ARP’s revolving credit facility

 

 

 

 

 

135,000

 

Repayments under ARP’s revolving credit facility

 

 

 

 

 

(55,000

)

ARP senior note repurchases

 

 

 

 

 

(5,528

)

Net proceeds from issuance of our subsidiaries’ units to the public

 

 

 

 

 

(1,319

)

Dividends to preferred unitholders

 

 

 

 

 

(1,015

)

Deferred financing costs, distribution equivalent rights and other

 

 

(8

)

 

 

(697

)

Net cash provided by (used in) financing activities

 

 

(8

)

 

 

67,191

 

Net change in cash and cash equivalents

 

 

(93

)

 

 

16,780

 

Cash and cash equivalents, beginning of year

 

 

12,009

 

 

 

31,214

 

Cash and cash equivalents, end of period

 

$

11,916

 

 

$

47,994

 

 

See accompanying notes to condensed consolidated financial statements.

9


 

ATLAS ENERGY GROUP, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—ORGANIZATION

We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our consolidated subsidiaries.

Our operations primarily consist of our ownership interests in the following:

 

Commencing September 1, 2016, Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”);

 

Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP.  As discussed further below, ARP was the predecessor to the business and operations of Titan;

 

All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and

 

12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.

At March 31, 2017, we had 26,061,818 common units issued and outstanding.

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of ARP’s and such subsidiaries’ lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

 

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

 

 

ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.

10


 

 

ARP’s second lien lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, ARP’s second lien lenders received a pro rata share of 10% of Titan’s common shares, subject to dilution by a management incentive plan.

 

ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of Titan’s common shares, subject to dilution by a management incentive plan.

 

all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

 

ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.

 

Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.

NOTE 2—BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and the applicable rules and regulations of the Securities Exchange Commission regarding interim financial reporting  and include all adjustments that are necessary for a fair presentation of our consolidated results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The consolidated results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed consolidated balance sheet was derived from audited financial statements but does not include all disclosures required by U.S. GAAP. For a more complete discussion of our accounting policies and certain other information, refer to our consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31 2016.

We determined that ARP (through the Plan Effective Date, as discussed further below) and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct the activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidated the financial statements of ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP into our condensed consolidated financial statements. Our consolidated VIE’s operating results and asset balances are presented separately in Note 10 – Operating Segment Information. As the general partner for both ARP (through the Plan Effective Date) and AGP, we have unlimited liability for the obligations of ARP (through the Plan Effective Date) and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed consolidated statements of operations and as a component of unitholders’ equity on the condensed consolidated balance sheets. All material intercompany transactions have been eliminated.

 

In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our condensed consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating

11


 

and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our condensed consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our condensed consolidated financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.

Certain reclassifications have been made to our condensed consolidated financial statements for the prior year periods to conform to classifications used in the current year, specifically related to ARP’s Drilling Partnerships management, which includes all of ARP’s managing and operating activities specific to ARP’s Drilling Partnerships including well construction and completion, administration and oversight, well services and gathering and processing. We previously presented these revenue and expense items separately; however, due to the deconsolidation of ARP on the date of the Chapter 11 Filings, we have aggregated these items to be presented as one combined revenue item and one combined expense item. As a result of this change, we have restated our prior year condensed consolidated statements of operations to conform to our current presentation.

In accordance with established practice in the oil and gas industry, our condensed consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest through the date of ARP’s Chapter 11 Filings. Such interests generally approximate 30%. Our condensed consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships through the date of ARP’s Chapter 11 Filings. Rather, ARP calculated these items specific to its own economics through the date of ARP’s Chapter 11 Filings.

On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.

Liquidity, Capital Resources, and Ability to Continue as a Going Concern

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP are currently paying distributions.  Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures, which we expect to fund through operating cash flow, and cash distributions received. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.

The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. If we are unable to remain in compliance with the covenants under our credit agreements (as described in Note 4), absent relief from our lenders, we maybe be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit agreements could elect to declare all amounts outstanding immediately due and payable and could terminate all commitments to extend further credit. If an event of default occurs, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. In addition to the $39.0 million of indebtedness due on September 30, 2017, we classified the remaining $47.9 million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $85.8 million of outstanding indebtedness under our credit agreements, which is net of $0.9 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net on our condensed consolidated balance sheet as of March 31, 2017.

We continually monitor our capital markets and capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets.

12


 

Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Atlas Growth Partners – Liquidity, Capital Resources, and Ability to Continue as a Going Concern

AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2017. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.

On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce AGP’s general and administrative expenses, the majority of which represent allocations from us.

Use of Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our condensed consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our condensed consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion of gas and oil properties, and fair value of derivative instruments. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Equity Method Investments

Investment in Titan. At March 31, 2017, we had a 2% Series A Preferred interest in Titan. We account for our investment under the equity method of accounting due to our ability to exercise significant influence.  As of March 31, 2017 and December 31, 2016, the net carrying amount of our investment in Titan was $0.5 million and zero, respectively. During the three months ended March 31, 2017, we recognized equity income of $0.5 million, within other, net on our condensed consolidated statements of operations.

Investment in Lightfoot. At March 31, 2017, we had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P. We account for our investment in Lightfoot under the equity method of accounting due to our ability to exercise significant influence. As of March 31, 2017 and December 31, 2016, the net carrying amount of our investment in Lightfoot was $18.6 million and $18.7 million, respectively. During both the three months ended March 31, 2017 and 2016, we recognized equity income of $0.2 million within other, net on our condensed consolidated statements of operations. During the three months ended March 31, 2017 and 2016, we received net cash distributions of approximately $0.4 million and $0.5 million, respectively.

13


 

Rabbi Trust

In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At March 31, 2017 and December 31, 2016, we reflected $2.2 million and $4.2 million, respectively, related to the value of the rabbi trust within other assets, net on our condensed consolidated balance sheets, and recorded corresponding liabilities of $2.2 million and $4.2 million, respectively, as of those same dates, within asset retirement obligations and other on our condensed consolidated balance sheets. During the three months ended March 31, 2017 and 2016, we distributed $2.1 million and $2.3 million, respectively, to certain executives related to the rabbi trust.

Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common units outstanding during the period.

The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands):

 

 

 

Three Months Ended

March 31

 

 

 

2017

 

 

2016

 

Net loss

 

$

(4,903

)

 

$

(1,272

)

Preferred unitholders’ dividends

 

 

 

 

 

(339

)

(Income) loss attributable to non-controlling interests

 

 

281

 

 

 

(5,340

)

Net loss attributable to common unitholders

 

 

(4,622

)

 

 

(6,951

)

Less: Net income attributable to participating securities – phantom units(1)

 

 

 

 

 

 

Net loss utilized in the calculation of net loss attributable to common unitholders per unit – diluted(1)

 

$

(4,622

)

 

$

(6,951

)

 

(1)

Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the three months ended March 31, 2017 and 2016, net loss attributable to common unitholder’s ownership interest was not allocated to approximately 178,000 and 263,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.

Diluted net income (loss) attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

14


 

The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands):

 

 

 

Three Months Ended

March 31

 

 

 

2017

 

 

2016

 

Weighted average number of common units—basic

 

 

26,062

 

 

 

26,028

 

Add effect of dilutive incentive awards(1)

 

 

 

 

 

 

Add effect of dilutive convertible preferred units and warrants(2)

 

 

 

 

 

 

Weighted average number of common units—diluted

 

 

26,062

 

 

 

26,028

 

 

(1)

For the three months ended March 31, 2017 and 2016, approximately 3,521,000 and 2,689,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

(2)

Our warrants issued in connection with the Second Lien Credit Agreement in 2016 and our convertible Series A Preferred Units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such warrants and units would have been anti-dilutive.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed combined consolidated financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

NOTE 3—PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated (in thousands):

 

 

 

March 31,

 

 

December 31,

 

 

 

2017

  

 

2016

 

Natural gas and oil properties:

 

 

 

 

 

 

 

 

Proved properties

 

$

84,619

 

 

$

84,631

 

Unproved properties

 

 

63,322

 

 

 

63,314

 

Support equipment and other

 

 

3,188

 

 

 

3,188

 

Total natural gas and oil properties

 

 

151,129

 

 

 

151,133

 

Less – accumulated depreciation, depletion and amortization

 

 

(83,363

)

 

 

(82,234

)

 

 

$

67,766

 

 

$

68,899

 

15


 

During the three months ended March 31, 2016, we recognized $18.7 million of non-cash investing activities capital expenditures, which were reflected within the changes in accounts payable and accrued liabilities on our condensed consolidated statements of cash flows.  

We capitalized interest on ARP’s borrowed funds related to capital projects only for periods that activities were in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP was 6.7% for the three months ended March 31, 2016. The aggregate amount of interest capitalized by ARP was $2.4 million for the three months ended March 31, 2016.

For the three months ended March 31, 2016, we recorded $1.7 million of ARP’s, accretion expense related to asset retirement obligations within depreciation, depletion and amortization in our condensed consolidated statements of operations.  For the three months ended March 31, 2016, ARP recorded liabilities of $2.8 million in asset retirement obligations in our condensed consolidated balance sheet due to the liquidation of some of ARP’s Drilling Partnerships.

NOTE 4—DEBT

Total debt consists of the following at the dates indicated (in thousands):

 

 

 

March 31,

 

December 31,

 

 

 

2017

 

 

2016

 

First Lien Credit Agreement

 

$

39,003

 

 

$

37,962

 

Second Lien Credit Agreement

 

 

47,855

 

 

 

44,593

 

Debt discount, net of accumulated amortization of $934 and $623

 

 

(934

)

 

 

(1,244

)

Deferred financing costs, net of accumulated amortization of $2,588 and $2,538, respectively

 

 

(168

)

 

 

(211

)

Total debt, net

 

 

85,756

 

 

 

81,100

 

Less current maturities

 

 

(85,756

)

 

 

(81,100

)

Total long-term debt, net

 

$

 

 

$

 

  

Cash Interest. Cash payments for interest were $0.2 million and $42.6 million for the three months ended March 31, 2017 and 2016, respectively.

Credit Agreements

First Lien Credit Agreement. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).

The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our condensed consolidated statement of operations for the three months ended March 31, 2016.  The Third Amendment amended the First Lien Credit Agreement to, among other things:

 

provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

 

shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

 

modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

16


 

 

allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

 

provide that the First Lien Credit Agreement may be prepaid without premium;

 

replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in Titan’s credit agreement, beginning with the quarter ending June 30, 2016;

 

prohibit the payment of cash distributions on our common and preferred units;

 

require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and

 

add a cross-default provision for defaults by ARP.

On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removed the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement also has an unamortized discount of $0.9 million as of March 31, 2017, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement.

The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.

Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.

The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.

The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.

On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

17


 

In addition to the $39.0 million of amounts outstanding under our First Lien Credit Agreement due on September 30, 2017, we classified the $47.9 million of amounts outstanding our Second Lien Credit Agreement as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $85.8 million of outstanding indebtedness under our credit agreements, which is net of $0.9 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net on our condensed combined consolidated balance sheet as of March 31, 2017.

NOTE 5—DERIVATIVE INSTRUMENTS

We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities.  We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are based on the respective Mt. Belvieu price.  These contracts were recorded at their fair values.

We recorded net derivative assets on our condensed consolidated balance sheets of $0.2 million at March 31, 2017 and net derivative liabilities of $0.6 million at December 31, 2016. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).

The following table summarizes the commodity derivative activity and presentation in our condensed consolidated statement of operations for the periods indicated (in thousands):

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets(1)

 

$

 

 

$

3,515

 

Portion of settlements attributable to subsequent mark to market gains

 

 

52

 

 

 

45,430

 

Total cash settlements on commodity derivative contracts

 

$

52

 

 

$

48,945

 

 

 

 

 

 

 

 

 

 

Gains recognized on cash settlement(2)

 

$

52

 

 

$

6,025

 

Gains recognized on open derivative contracts(2)

 

 

705

 

 

 

40,428

 

Gains on mark-to-market derivatives

 

$

757

 

 

$

46,453

 

 

(1)

Recognized in gas and oil production revenue.

(2)

Recognized in gain (loss) on mark-to-market derivatives.

18


 

The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our condensed consolidated balance sheets as of the dates indicated (in thousands):

 

Offsetting Derivatives as of March 31, 2017

 

Gross

Amounts

Recognized

 

 

Gross

Amounts

Offset

 

 

Net Amount

Presented

 

Current portion of derivative assets

 

$

280

 

 

$

(148

)

 

$

132

 

Long-term portion of derivative assets

 

 

90

 

 

 

(53

)

 

 

37

 

Total derivative assets

 

$

370

 

 

$

(201

)

 

$

169

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative liabilities

 

$

(148

)

 

$

148

 

 

$

 

Long-term portion of derivative liabilities

 

 

(53

)

 

 

53

 

 

 

 

Total derivative liabilities

 

$

(201

)

 

$

201

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offsetting Derivatives as of December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative assets

 

$

97

 

 

$

(97

)

 

$

 

Long-term portion of derivative assets

 

 

 

 

 

 

 

 

 

Total derivative assets

 

$

97

 

 

$

(97

)

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of derivative liabilities

 

$

(381

)

 

$

97

 

 

$

(284

)

Long-term portion of derivative liabilities

 

 

(280

)

 

 

 

 

 

(280

)

Total derivative liabilities

 

$

(661

)

 

$

97

 

 

$

(564

)

 

At March 31, 2017, AGP had the following commodity derivatives:

 

Type

 

Production

Period Ending

December 31,

 

 

 

Volumes(1)

 

 

Average

Fixed

Price(1)

 

 

Fair Value

Asset

 

 

Total Type

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)(2)

 

 

(in thousands)(2)

 

Crude Oil – Fixed Price Swaps

 

2017(3)

 

 

 

80,400

 

 

$

53.298

 

 

$

127

 

 

 

 

 

 

 

2018

 

 

 

74,500

 

 

$

52.510

 

 

$

42

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

AGP’s net assets

 

 

$

169

 

 

(1)

Volumes for crude oil are stated in barrels.

(2)

Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable.

(3)

The production volumes for 2017 include the remaining nine months of 2017 beginning April 1, 2017.

NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We use a market approach fair value methodology to value our outstanding derivative contracts and financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate the fair value of our financial instruments into the three level hierarchy (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2017 and December 31, 2016, all of our derivative financial instruments were classified as Level 2.

19


 

Information for our financial instruments measured at fair value were as follows (in thousands):

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

As of March 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rabbi trust

 

$

2,187

 

 

$

 

 

$

 

 

$

2,187

 

AGP Commodity swaps

 

 

 

 

 

370

 

 

 

 

 

 

370

 

Total assets, gross

 

 

2,187

 

 

 

370

 

 

 

 

 

 

2,557

 

Liabilities, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

AGP Commodity swaps

 

 

 

 

 

(201

)

 

 

 

 

 

(201

)

Total derivative liabilities, gross

 

 

 

 

 

(201

)

 

 

 

 

 

(201

)

Total assets, fair value, net

 

$

2,187

 

 

$

169

 

 

$

 

 

$

2,356

 

As of December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rabbi trust

 

$

4,208

 

 

$

 

 

$

 

 

$

4,208

 

AGP Commodity swaps

 

 

 

 

 

97

 

 

 

 

 

 

97

 

Total assets, gross

 

 

4,208

 

 

 

97

 

 

 

 

 

 

4,305

 

Liabilities, gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

AGP Commodity swaps

 

 

 

 

 

(661

)

 

 

 

 

 

(661

)

Total derivative liabilities, gross

 

$

 

 

 

(661

)

 

 

 

 

 

(661

)

Total assets, fair value, net

 

$

4,208

 

 

$

(564

)

 

$

 

 

$

3,644

 

 

Other Financial Instruments

Our other current assets and liabilities on our condensed consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair value of our debt at March 31, 2017 approximated its carrying value of $86.9 million, which consisted of our First Lien Credit Agreement and Second Lien Credit Agreement that bear interest at variable rates and are categorized as Level 1 values.

NOTE 7—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with ARP. ARP did not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).

Relationship with Titan. Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On September 1, 2016, Titan entered into a Delegation of Management Agreement (the “Delegation Agreement”) with Titan Management, our wholly owned subsidiary. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and powers to manage and control the business and affairs of Titan Energy Operating, LLC (“Titan Operating”), a wholly owned subsidiary of Titan. However, Titan’s board of directors retains management and control over certain non-delegated duties.  In addition, Titan also entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan Management, Atlas Energy Resource Services, Inc. (“AERS”), our wholly owned subsidiary, and Titan Operating. Pursuant to the Omnibus Agreement, Titan Management and AERS will provide Titan and Titan Operating with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse Titan Management and AERS for their direct and allocable indirect expenses incurred in connection with the provision of the services, subject to certain approval rights in favor of Titan’s Conflicts Committee. As of March 31, 2017 and December 31, 2016, we had payables of $8.9 million and $3.3 million to Titan related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances from affiliates in our condensed combined consolidated balance sheet.

20


 

Relationship with AGP. AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During both the three months ended March 31, 2017 and 2016, AGP paid $0.6 million related to AGP GP for this management fee, respectively. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP reimburses all necessary and reasonable indirect costs allocated by the general partner.

Relationship with Drilling Partnerships. ARP conducted certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Through the Plan Effective Date, ARP served as the ultimate general partner and operator of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP was liable for the Drilling Partnerships’ liabilities and could have been liable to limited partners of the Drilling Partnerships if it breached its responsibilities with respect to the operations of the Drilling Partnerships. ARP was entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements. In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program.

AGP’s Relationship with Titan. At our direction, AGP reimburses Titan for direct costs, such as salaries and wages, charged to AGP based on our employees who incurred time to activities on AGP’s behalf and indirect costs, such as rent and other general and administrative costs, allocated to AGP based on the number of our employees who devoted their time to activities on AGP’s behalf. As of March 31, 2017 and December 31, 2016, AGP had payables of $1.3 million and $0.8 million to Titan related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the condensed combined consolidated balance sheet.

Other Relationships. We have other related party transactions with regard to our First Lien Credit Agreement and Second Lien Credit Agreement (see Note 4), our Series A preferred units and our general partner and limited partner interest in Lightfoot (see Notes 1 and 2).

NOTE 8—COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are parties to various routine legal proceedings arising out of the ordinary course of business. Our management and our subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

Environmental Matters

We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We maintain insurance which may cover in whole or in part certain environmental expenditures. We had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of March 31, 2017 and December 31, 2016.

NOTE 9—CASH DISTRIBUTIONS

Our Cash Distributions. We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our limited liability company agreement) for that quarter to our unitholders. However, as a result of the First Lien Credit Agreement and Second Lien Credit Agreement entered into on March 30, 2016 (see Note 4), we are prohibited from paying future cash distributions on our common and preferred units. During the three months ended March 31, 2016, we paid a distribution of $1.0 million to our Class A preferred unitholders.  

ARP Cash Distributions. ARP had a monthly cash distribution program whereby ARP distributed all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s

21


 

common unit distributions in any quarter exceeded specified target levels, we received between 13% and 48% of such distributions in excess of the specified target levels.

 

During the three months ended March 31, 2016, ARP paid three monthly cash distributions totaling approximately $3.8 million to its common limited partners ($0.0125 per unit per month); $1.9 million to its Preferred Class C limited partners ($0.17 per unit per month); and $0.1 million to us as its General Partner Class A holder ($0.0125 per unit per month).

 

During the three months ended March 31, 2016, ARP paid a distribution of $2.2 million to its Class D Preferred limited partners ($0.5390625 per unit) for the period October 15, 2015 through January 14, 2016. During the three months ended March 31, 2016, ARP paid a distribution of $0.2 million to its Class E Preferred limited partners ($0.671875 per unit) for the period October 15, 2015 through January 14, 2016.

AGP Cash Distributions. During the three months ended March 31, 2016, AGP paid a distribution of $4.1 million to common limited partners ($0.1750 per unit) and $0.1 million to the general partner’s Class A units ($0.1750 per unit). On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets.

22


 

NOTE 10—OPERATING SEGMENT INFORMATION

Our operations included three reportable operating segments: ARP (through the date of the Chapter 11 Filings), AGP, and corporate and other. These operating segments reflected the way we managed our operations and made business decisions. Corporate and other includes our equity investments in Lightfoot (see Note 2) and Titan (see Note 2), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

Atlas Resource Partners:

 

 

 

 

 

 

 

 

Revenues

 

$

 

 

$

103,217

 

Operating costs and expenses

 

 

 

 

 

(59,202

)

Depreciation, depletion and amortization expense

 

 

 

 

 

(30,045

)

Interest expense

 

 

 

 

 

(27,705

)

Gain on early extinguishment of debt

 

 

 

 

 

26,498

 

Segment income

 

$

 

 

$

12,763

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Revenues

 

$

3,153

 

 

$

3,434

 

Operating costs and expenses

 

 

(2,333

)

 

 

(3,503

)

Depreciation, depletion and amortization expense

 

 

(1,112

)

 

 

(4,227

)

Segment loss

 

$

(292

)

 

$

(4,296

)

Corporate and other:

 

 

 

 

 

 

 

 

Revenues

 

$

722

 

 

$

211

 

General and administrative

 

 

(404

)

 

 

(2,154

)

Gain on asset sales and disposal

 

 

 

 

 

 

Interest expense

 

 

(4,929

)

 

 

(1,743

)

Loss on early extinguishment of debt

 

 

 

 

 

(6,053

)

Segment loss

 

$

(4,611

)

 

$

(9,739

)

Reconciliation of segment income (loss) to net loss:

 

 

 

 

 

 

 

 

Segment income (loss):

 

 

 

 

 

 

 

 

Atlas Resource Partners

 

$

 

 

$

12,763

 

Atlas Growth Partners

 

 

(292

)

 

 

(4,296

)

Corporate and other

 

 

(4,611

)

 

 

(9,739

)

Net loss

 

$

(4,903

)

 

$

(1,272

)

Reconciliation of segment revenues to total revenues:

 

 

 

 

 

 

 

 

Segment revenues:

 

 

 

 

 

 

 

 

Atlas Resource Partners

 

$

 

 

$

103,217

 

Atlas Growth Partners

 

 

3,153

 

 

 

3,434

 

Corporate and other

 

 

722

 

 

 

211

 

Total revenues

 

$

3,875

 

 

$

106,862

 

Capital expenditures:

 

 

 

 

 

 

 

 

Atlas Resource Partners

 

$

 

 

$

13,170

 

Atlas Growth Partners

 

 

 

 

 

5,549

 

Total capital expenditures

 

$

 

 

$

18,719

 

 

 

 

March 31,

 

 

December 31,

 

 

 

2017

 

 

2016

 

Balance sheet:

 

 

 

 

 

 

 

 

Total assets:

 

 

 

 

 

 

 

 

Atlas Growth Partners

 

$

77,818

 

 

$

78,500

 

Corporate and other

 

 

24,449

 

 

 

26,576

 

Total assets

 

$

102,267

 

 

$

105,076

 

 

23


 

NOTE 11—SUBSEQUENT EVENTS

Conversion of Series A Preferred Units. On May 5, 2017, the holders of all 1.9 million of our outstanding Series A Preferred Units elected to convert their units into 5.9 million common units.

24


 

ITEM 2:

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS OVERVIEW

We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our and consolidated subsidiaries.

Our operations primarily consisted of our ownership interests in the following:

 

Commencing September 1, 2016, Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States but primarily focused on the horizontal development of resource potential from the Eagle Ford Shale in South Texas. Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”);

 

Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP.  As discussed further below, ARP was the predecessor to the business and operations of Titan;

 

All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and

 

12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.

Our cash flows and liquidity are substantially dependent upon AGP’s annual management fee and distributions from AGP, Lightfoot, and Titan. Neither AGP nor Titan are currently paying distributions. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP) for financial reporting purposes, AGP’s annual management fee and distributions from Lightfoot are currently our only sources of liquidity to satisfy our obligations under our credit agreements. In addition, the obligations under our first lien credit agreement mature in September 2017. As a result, we continue to face significant liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and strengthen our balance sheet. Please see “Liquidity, Capital Resources, and Ability to Continue as a Going Concern” for additional disclosures.

ARP Restructuring and Emergence from Chapter 11 Proceedings

On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain of ARP’s and their subsidiaries’ lenders (the “Restructuring Support Parties”) to support ARP’s restructuring pursuant to a pre-packaged plan of reorganization (the “Plan”).

On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”

On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:

 

ARP’s first lien lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and

25


 

 

became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.

 

ARP’s second lien lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, ARP’s second lien lenders received a pro rata share of 10% of Titan’s common shares, subject to dilution by a management incentive plan.

 

ARP’s senior note holders, in exchange for 100% of the $668 million aggregate principal amount of senior notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of Titan’s common shares, subject to dilution by a management incentive plan.

 

all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.

 

ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.

 

Titan Management, our wholly owned subsidiary, received a Series A Preferred Share, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to dilution if catch-up contributions are not made with respect to future equity issuances, other than pursuant to the management incentive plan) and certain other rights as provided for in the Restructuring Support Agreement. Four of the seven initial members of the board of directors were designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in our limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of us unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.

We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.

FINANCIAL PRESENTATION

Our condensed consolidated financial statements contain our accounts and those of our condensed consolidated subsidiaries as of March 31, 2017. We determined that ARP (through the Plan Effective Date, as discussed further below) and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct the activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidated the financial statements of ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP into our condensed consolidated financial statements. As the general partner for both ARP (through the Plan Effective Date) and AGP, we have unlimited liability for the obligations of ARP (through the Plan Effective Date) and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP are reflected as (income) loss attributable to non-controlling interests in the condensed consolidated statements of operations and as a component of unitholders’ equity on the condensed consolidated balance sheets. All material intercompany transactions have been eliminated.

In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our condensed consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our condensed consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our condensed consolidated financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.

On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial

26


 

interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.

Throughout this section, when we refer to “our” condensed consolidated financial statements, we are referring to the condensed consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP (as applicable) and AGP, adjusted for non-controlling interests in ARP and AGP.

GENERAL TRENDS AND OUTLOOK

We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 and have continued to remain low in 2017. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debts and the ability to make distributions to unitholders, including AGP’s ability to make distributions to us, depend on our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. Our subsidiaries face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. Our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced. To the extent our subsidiaries do not have sufficient capital, our subsidiaries’ ability to drill and acquire more reserves will be negatively impacted.

RESULTS OF OPERATIONS

Gas and Oil Production

We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 condensed consolidated financial statements will not be comparable to our 2017 condensed consolidated financial statements.

Production Profile. Currently, our gas and oil production revenues and expenses consist of our gas and oil production activities derived from our wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. We have established production positions in the following operating areas:

 

the Eagle Ford Shale in southern Texas, an oil-rich area, in which we acquired acreage in November 2014, represents over ninety percent of our operations;

 

the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, contains liquids rich natural gas and oil; and,

 

the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area.

27


 

The following table presents the number of wells our subsidiaries drilled and the number of wells our subsidiaries turned in line, both gross and for our respective interests, during the periods indicated:

 

 

 

Three Months Ended

March 31,

 

 

 

2017(1)

 

 

2016(1)

 

 

 

 

 

 

 

 

 

 

Gross wells drilled(4)

 

 

 

 

 

 

Net wells drilled(2)

 

 

 

 

 

 

Gross wells turned in line(3)

 

 

 

 

 

2

 

Net wells turned in line(2)(3)

 

 

 

 

 

2

 

 

(1)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2017 results.  In addition, ARP did not have any gross or net wells drilled or turned in line, did not drill any exploratory wells, and did not have any gross or net dry wells within its operating areas during the three months ended March 31, 2016.

(2)

Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.

(3)

Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.

(4)

AGP did not drill any exploratory wells and did not have any gross or net dry wells within its operating areas during the periods presented.

 

28


 

Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the periods indicated:

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

Production:(1)

 

 

 

 

 

 

 

 

Atlas Resource Partners: (2)

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

 

 

 

17,704

 

Oil (MBbls)

 

 

 

 

 

415

 

NGLs (MBbls)

 

 

 

 

 

228

 

Total (MMcfe)

 

 

 

 

 

21,565

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

32

 

 

 

46

 

Oil (MBbls)

 

 

44

 

 

 

104

 

NGLs (MBbls)

 

 

5

 

 

 

8

 

Total (MMcfe)

 

 

327

 

 

 

713

 

Total production: (2)

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

32

 

 

 

17,750

 

Oil (MBbls)

 

 

44

 

 

 

519

 

NGLs (MBbls)

 

 

5

 

 

 

236

 

Total (MMcfe)

 

 

327

 

 

 

22,279

 

Production per day:(1)

 

 

 

 

 

 

 

 

Atlas Resource Partners: (2)

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

 

 

 

194,550

 

Oil (Bpd)

 

 

 

 

 

4,563

 

NGLs (Bpd)

 

 

 

 

 

2,509

 

Total (Mcfed)

 

 

 

 

 

236,983

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

354

 

 

 

500

 

Oil (Bpd)

 

 

485

 

 

 

1,138

 

NGLs (Bpd)

 

 

60

 

 

 

85

 

Total (Mcfed)

 

 

3,628

 

 

 

7,839

 

Total production per day: (2)

 

 

 

 

 

 

 

 

Natural gas (Mcfd)

 

 

354

 

 

 

195,051

 

Oil (Bpd)

 

 

485

 

 

 

5,701

 

NGLs (Bpd)

 

 

60

 

 

 

2,594

 

Total (Mcfed)

 

 

3,628

 

 

 

244,821

 

 

(1)

Production quantities consist of the sum of (i) the proportionate share of production from wells in which our subsidiaries have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.

(2)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2017 results.

29


 

Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for AGP’s and ARP’s natural gas, oil, and NGLs production for each of the periods indicated, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

Production revenues (in thousands):

 

 

 

 

 

 

 

 

Atlas Resource Partners: (1)

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

 

 

$

31,284

 

Oil revenue

 

 

 

 

 

15,312

 

NGLs revenue

 

 

 

 

 

1,896

 

Total revenues

 

$

 

 

$

48,492

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

101

 

 

$

87

 

Oil revenue

 

 

2,185

 

 

 

2,934

 

NGLs revenue

 

 

110

 

 

 

80

 

Total revenues

 

$

2,396

 

 

$

3,101

 

Total production revenues: (1)

 

 

 

 

 

 

 

 

Natural gas revenue

 

$

101

 

 

$

31,371

 

Oil revenue

 

 

2,185

 

 

 

18,246

 

NGLs revenue

 

 

110

 

 

 

1,976

 

Total revenues

 

$

2,396

 

 

$

51,593

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

Atlas Resource Partners: (1)

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

 

 

 

 

 

 

 

Total realized price, after hedge(2)(3)

 

$

 

 

$

3.41

 

Total realized price, before hedge(2)

 

$

 

 

$

1.78

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

 

 

$

77.16

 

Total realized price, before hedge

 

$

 

 

$

29.51

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

 

 

$

8.31

 

Total realized price, before hedge

 

$

 

 

$

8.31

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

Total realized price, after hedge

 

$

3.19

 

 

$

1.91

 

Total realized price, before hedge

 

$

3.19

 

 

$

1.91

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

Total realized price, after hedge(3)

 

$

50.55

 

 

$

30.62

 

Total realized price, before hedge

 

$

50.00

 

 

$

28.33

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

Total realized price, after hedge

 

$

20.21

 

 

$

10.34

 

Total realized price, before hedge

 

$

20.21

 

 

$

10.34

 

 

 

 

 

 

 

 

 

 

Production costs (per Mcfe):

 

 

 

 

 

 

 

 

Atlas Resource Partners: (1)

 

 

 

 

 

 

 

 

Lease operating expenses(4)

 

$

 

 

$

1.25

 

Production taxes

 

 

 

 

 

0.18

 

Transportation and compression

 

 

 

 

 

0.26

 

 

 

$

 

 

$

1.69

 

Atlas Growth Partners:

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

2.35

 

 

$

0.85

 

Production taxes

 

 

0.46

 

 

 

0.21

 

Transportation and compression

 

 

0.10

 

 

 

0.08

 

30


 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

 

 

$

2.91

 

 

$

1.14

 

Total production costs: (1)

 

 

 

 

 

 

 

 

Lease operating expenses(4)

 

$

2.35

 

 

$

1.24

 

Production taxes

 

 

0.46

 

 

 

0.18

 

Transportation and compression

 

 

0.10

 

 

 

0.25

 

 

 

$

2.91

 

 

$

1.67

 

(1)

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2017 results.

(2)

Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the three months ended March 31, 2016. Including the effect of this subordination, ARP’s average realized gas sales price was $3.37 per Mcf ($1.74 per Mcf before the effects of financial hedging) for the three months ended March 31, 2016.

(3)

Includes the impact of $0.1 million and $0.2 million of cash settlements for the three months ended March 31, 2017 and 2016, respectively, on AGP’s oil derivative contracts which were entered into subsequent to our decision to discontinue hedge accounting beginning on January 1, 2015. Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following ARP’s decision to de-designate hedges beginning on January 1, 2015. Cash settlements on ARP’s commodity derivative contracts excluded from production revenues consisted of $28.5 million associated with natural gas derivative contracts and $16.7 million associated with crude oil derivative contracts for the three months ended March 31, 2016.

(4)

Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the three months ended March 31, 2016. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.23 per Mcfe ($1.66 per Mcfe for total production costs) for the three months ended March 31, 2016. Including the effects of these costs, total lease operating expenses per Mcfe were $1.21 per Mcfe ($1.65 per Mcfe for total production costs) for the three years ended March 31, 2016.

 

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

 

 

(in thousands)

Gas and oil production revenues

 

$

2,396

 

 

$

51,593

 

Gas and oil production costs

 

$

952

 

 

$

36,656

 

 Our production revenues were lower in the current quarter as a result of a $48.5 million decrease in ARP’s revenues due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, and a $$0.7 million decrease in AGP’s revenues attributable to production from AGP’s Eagle Ford operations, primarily related to two wells turned in line in the prior period resulting in lower volumes from natural decline in the current period.

Our production costs were lower in the current quarter as a result of a $35.8 million decrease in ARP’s gas and oil production costs due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented, partially offset by a $0.2 million in increase in AGP’s gas and oil production costs primarily related to maintenance costs attributable to AGP’s Eagle Ford operations.

 

31


 

ARP’s Drilling Partnership Management

The following table presents the amounts of revenues and the related costs associated with these revenues during the periods indicated (dollars in thousands). We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 condensed consolidated financial statements will not be comparable to our 2017 condensed consolidated financial statements.

 

 

 

Three Months Ended

March 31

 

 

2017

 

 

2016

 

ARP’s Drilling Partnership management revenues

 

$

 

 

$

8,482

 

ARP’s Drilling Partnership management expenses

 

 

 

 

 

6,283

 

ARP’s Drilling Partnership management gross profit margin

 

$

 

 

$

2,199

 

 

 

 

 

 

 

 

 

 

We deconsolidated ARP as of July 27, 2016, which affects the comparability of the periods presented for each of ARP’s Drilling Partnership management items above.

Other Revenues and Expenses

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

 

 

(in thousands)

Other Revenues

 

 

 

 

 

 

 

 

Gain on mark-to-market derivatives

 

$

757

 

 

$

46,453

 

Other, net

 

 

722

 

 

 

334

 

 

 

 

 

 

 

 

 

 

Other Expenses

 

 

 

 

 

 

 

 

General and administrative:

 

 

 

 

 

 

 

 

Atlas Energy Group

 

$

404

 

 

$

2,154

 

Atlas Growth Partners

 

 

1,381

 

 

 

2,689

 

Atlas Resource Partners

 

 

 

 

 

17,077

 

Total general and administrative

 

$

1,785

 

 

$

21,920

 

Depreciation, depletion and amortization:

 

 

 

 

 

 

 

 

Atlas Growth Partners

 

$

1,112

 

 

$

4,227

 

Atlas Resource Partners

 

 

 

 

 

30,045

 

Total depreciation, depletion and amortization

 

$

1,112

 

 

$

34,272

 

Interest expense:

 

 

 

 

 

 

 

 

Atlas Energy Group

 

$

4,929

 

 

$

1,743

 

Atlas Resource Partners

 

 

 

 

 

27,705

 

Total interest expense

 

$

4,929

 

 

$

29,448

 

(Gain) loss on extinguishment of debts, net:

 

 

 

 

 

 

 

 

Atlas Energy Group

 

$

 

 

$

6,053

 

Atlas Resource Partners

 

 

 

 

 

(26,498

)

Total (gain) loss on extinguishment of debts, net

 

$

 

 

$

(20,445

)

(Income) loss attributable to non-controlling interests

 

 

281

 

 

 

(5,340

)

 

Gain (Loss) on Mark-to-Market Derivatives. We recognize changes in the fair value of their derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized gains during the three months ended March 31, 2017 and 2016 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior year end. In addition, we deconsolidated ARP as of July 27, 2016, which resulted in a decrease of $46.1 million and affects the comparability of the periods presented.

32


 

 

Other, net. Our other, net revenues were higher in the current quarter as a result of a $0.5 million increase in equity method income related to our 2% Series A Preferred interest in Titan.  

General and Administrative. Our $1.8 million decrease in general and administrative expenses in the current quarter was primarily due to a $1.9 million decrease in stock compensation expense, partially offset by a $0.1 million increase in other corporate activities. ARP’s $17.1 million decrease in general and administrative expenses in the current quarter was due to our deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s decrease in general and administrative expenses in the current quarter was due to a $1.4 million decrease in salaries, wages and other corporate activity costs allocated by us to AGP as a result of the suspension of AGP’s current primary offering efforts and AGP’s management’s plan to reduce general and administrative expenses.

Depreciation, Depletion and Amortization. ARP’s $30.0 million decrease in depreciation, depletion and amortization in the current quarter was due to our deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s decrease in depreciation, depletion and amortization in the current quarter was primarily due to $3.1 million decrease in AGP’s depletion expense due to impairments of its proved and unproved oil and gas properties in its Eagle Ford operating area recorded in the fourth quarter of 2016, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties.

Interest Expense. The increase in our interest expense in the current quarter consisted of a $4.3 million increase of paid-in-kind interest on our First Lien Credit Agreement and Second Lien Credit Agreement and a $0.3 million increase of amortization of warrants that were issued in connection with the Second Lien Credit Agreement, partially offset by a $1.3 million decrease in interest on the original term loans with Riverstone and a $0.2 million decrease in amortization of our deferred financing costs. ARP’s $27.7 million decrease interest expense in the current quarter was due to our deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.

Gain (Loss) on Early Extinguishment of Debt. The decrease in our loss on early extinguishment of debt in the current quarter was due to $3.7 million of accelerated amortization of deferred financing costs and $2.4 million of prepayment penalties related to the restructuring of our original term loans with Riverstone in the first quarter of 2016.  ARP’s $26.5 million decrease in gain on early extinguishment of debt was related to the repurchase of a portion of ARP’s senior notes in the first quarter of 2016.

(Income) Loss Attributable to Non-Controlling Interests. The decrease in loss attributable to non-controlling interests in the current quarter was primarily due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.

Liquidity, Capital Resources and Ability to Continue as a Going Concern

Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP is currently paying distributions. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In addition, the obligations under our first lien credit agreement mature in September 2017. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.

The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern.  If we are unable to remain in compliance with the covenants under our credit agreements, absent relief from our lenders, we maybe be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit agreements could elect to declare all amounts outstanding immediately due and payable and could terminate all commitments to extend further credit. If an event of default occurs, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. In addition to the $39.0 million of indebtedness due on September 30, 2017, we classified the remaining $47.9 million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance.  In total, we have $85.8 million of outstanding indebtedness under our credit agreements, which is net of $0.9 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net within our condensed consolidated balance sheet as of March 31, 2017.

We continually monitor our capital markets and capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to

33


 

address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our  debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets. Please see “Risk Factors—Tax Risks to Unitholders— We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.”

Our condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Atlas Growth Partners – Liquidity, Capital Resources, and Ability to Continue as a Going Concern

AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2017. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.

On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets.  Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce general and administrative expenses, the majority of which represent allocations from us.

Cash Flows

 

 

 

Three Months Ended

March 31,

 

 

 

2017

 

 

2016

 

Net cash used in operating activities

 

$

(85

 

$

(33,326

)

Net cash used in investing activities

 

 

 

 

 

(17,085

)

Net cash (used in) provided by financing activities

 

 

(8

)

 

 

67,191

 

Three Months Ended March 31, 2017 Compared with the Three Months Ended March 31, 2016

We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2017 cash flows will not be comparable to our 2016 cash flows.

 

Cash Flows From Operating Activities:

The change in cash flows used in operating activities compared with the prior year period was due to:

 

a decrease of $41.2 million of cash paid for interest related to ARP’s debts due to the deconsolidation of ARP on the date of the Chapter 11 Filings;

 

a decrease of $36.7 million of investor capital raised transferred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program in March of 2016;

34


 

 

a decrease of $9.4 million in distributions paid to non-controlling interests; and

 

a decrease of $1.2 million of cash paid for interest related to our First and Second Lien Credit Agreements; partially offset by

 

a decrease of cash settlement receipts of $48.9 million on commodity derivative contracts; and

 

a decrease of $9.9 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production and ARP’s Drilling partnership management revenue activities, and collections net of payments for our royalties, ARP’s Drilling partnership management expense activities, lease operating expenses, gathering, processing and transportation expenses, severance taxes, and general and administrative expenses.

 

Cash Flows From Investing Activities:

The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to a decrease of $18.7 million in capital expenditures related to ARP’s and AGP’s drilling activities.

 

Cash Flows From Financing Activities:

The change in cash flows (used in) provided by financing activities compared with the prior year period was due to:

 

a decrease of $80.0 million in net borrowings under ARP’s credit facilities; partially offset by

 

a $4.3 million decrease in net repayments on our original term loans with Riverstone;

 

a decrease of $5.5 million related to ARP’s senior note repurchases in the first quarter of 2016;

 

a decrease of $1.0 million in distributions paid to preferred unitholders primarily due to the suspension of distributions for the Series A preferred units in the first quarter of 2016;

 

a decrease of $1.3 million in net proceeds primarily due to fees related to AGP’s public offering in 2016; and

 

a decrease of $0.7 million in deferred financing costs and discounts.

Capital Requirements

 

 At March 31, 2017, the capital requirements of our natural gas and oil production primarily consist of expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures

 

As of March 31, 2017, our subsidiaries did not have any commitments for drilling and completion and capital expenditures, excluding acquisitions.

OFF BALANCE SHEET ARRANGEMENTS

There have been no material changes to our off balance sheet arrangements from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

There have been no material changes to our contractual obligations and commercial commitments from those disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

CREDIT FACILITIES

As of March 31, 2017, we had not guaranteed any of our subsidiaries’ obligations or debt instruments.

35


 

Credit Agreements

First Lien Credit Agreement. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).

The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our condensed consolidated statement of operations for the three months ended March 31, 2016.  The Third Amendment amended the First Lien Credit Agreement to, among other things:

 

provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);

 

shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;

 

modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;

 

allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;

 

provide that the First Lien Credit Agreement may be prepaid without premium;

 

replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;

 

prohibit the payment of cash distributions on our common and preferred units;

 

require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and

 

add a cross-default provision for defaults by ARP.

On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement also has an unamortized discount of $0.9 million as of March 31, 2017, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement.

The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.

Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will

36


 

be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.

The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.

The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.

In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities (and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.

On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removed the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Recently Issued Accounting Standards

See Note 2 to our condensed consolidated financial statements for additional information related to recently issued accounting standards.

ITEM 3:

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.

We are exposed to various market risks, principally changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on March 31, 2017. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.

Interest Rate Risk. As of March 31, 2017, we had $86.9 million of outstanding borrowings under our credit agreements. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our condensed consolidated interest expense for the year ending March 31, 2018 by $0.9 million.

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Commodity Price Risk. Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the year ending March 31, 2018 of $0.2 million, net of non-controlling interests.

As of March 31, 2017, AGP had the following commodity derivatives:

 

Type

 

Production

Period Ending

December 31,

 

 

Volumes(1)

 

 

Average

Fixed Price(1)

 

Crude Oil – Fixed Price Swaps

 

2017(2)

 

 

 

80,400

 

 

$

53.298

 

 

 

2018

 

 

 

74,500

 

 

$

52.510

 

 

(1)

Volumes for crude oil are stated in barrels.

(2)

The production volumes for 2017 include the remaining nine months of 2017 beginning April 1, 2017.

 

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ITEM 4:

CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Security and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2017, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

ITEM 6:

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

Exhibit
Number

 

Exhibit Description

 

 

   3.1

 

Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015 (incorporated by reference to our Current Report on Form 8-K filed March 2, 2015).

 

 

   3.2

 

Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of February 27, 2015 (incorporated by reference to our Current Report on Form 8-K filed March 2, 2015).

 

 

 

   3.3

 

Amendment No. 2 to the Third Amended and Restated Limited Liability Company Agreement of Atlas Energy Group, LLC, dated as of April 27, 2016 (incorporated by reference to our Current Report on Form 8-K filed April 29, 2016).

 

 

 

  31.1*

 

Rule 13(a)-14(a)/15(d)-14(a) Certification

 

 

 

  31.2*

 

Rule 13(a)-14(a)/15(d)-14(a) Certification

 

 

 

  32.1*

 

Section 1350 Certification

 

 

 

  32.2*

 

Section 1350 Certification

 

 

 

101.INS**

 

XBRL Instance Document

 

 

 

101.SCH**

 

XBRL Schema Document

 

 

 

101.CAL**

 

XBRL Calculation Linkbase Document

 

 

 

101.LAB**

 

XBRL Label Linkbase Documen

 

 

 

101.PRE**

 

XBRL Presentation Linkbase Document

 

 

 

101.DEF**

 

XBRL Definition Linkbase Document

 

*

Provided herewith.

**

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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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, thereunto duly authorized.

 

 

 

ATLAS ENERGY GROUP, LLC

 

 

 

Date:  May 15, 2017

 

By:

 

/s/ EDWARD E. COHEN

 

 

 

 

Edward E. Cohen

Chief Executive Officer

Date:  May 15, 2017

 

By:

 

/s/ JEFFREY M. SLOTTERBACK

 

 

 

 

Jeffrey M. Slotterback

Chief Financial Officer

Date:  May 15, 2017

 

By:

 

/s/ MATTHEW J. FINKBEINER

 

 

 

 

Matthew J. Finkbeiner

Chief Accounting Officer

 

 

40