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 September 30, 2018
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: 000-55603
Atlas Growth Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware | | 80-0906030 |
(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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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 ☒
The number of outstanding common limited partner units of the registrant on November 16, 2018 was 23,300,410.
ATLAS GROWTH PARTNERS, L.P.
INDEX TO ANNUAL REPORT
ON FORM 10-Q
TABLE OF CONTENTS
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:
| • | our ability to obtain long-term financing for our property acquisitions and drilling activities in a timely manner; |
| • | the suspension of our quarterly distribution; |
| • | our lack of ability to raise capital, in the capital markets or otherwise; |
| • | our ability to continue as a going concern; |
| • | our business and investment strategy; |
| • | the effect of general market, oil and gas market (including volatility of realized price for oil, natural gas and natural gas liquids), and economic and political conditions; |
| • | uncertainties with respect to identified drilling locations and estimates of reserves; |
| • | our ability to generate sufficient cash flows to make distributions to our unitholders; |
| • | the degree and nature of our competition; and |
| • | the availability of qualified personnel at our general partner and Atlas Energy Group, LLC. |
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, 2017. 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.
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.
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ATLAS GROWTH PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)
| | September 30, | | | December 31, | |
| | 2018 | | | 2017 | |
ASSETS | | | | | | | | |
Current assets: | | | | | | | | |
Cash and cash equivalents | | $ | 2,480 | | | $ | 8,236 | |
Accounts receivable | | | 870 | | | | 572 | |
Advances to affiliates | | | 459 | | | | — | |
Total current assets | | | 3,809 | | | | 8,808 | |
Property, plant and equipment, net | | | 68,199 | | | | 65,293 | |
Other assets, net | | | 80 | | | | 118 | |
Total assets | | $ | 72,088 | | | $ | 74,219 | |
LIABILITIES AND PARTNERS’ CAPITAL | | | | | | | | |
Current liabilities: | | | | | | | | |
Accounts payable | | $ | 830 | | | $ | 332 | |
Advances from affiliates | | | — | | | | 606 | |
Current portion of derivative liability | | | 361 | | | | 497 | |
Accrued liabilities | | | 291 | | | | 407 | |
Total current liabilities | | | 1,482 | | | | 1,842 | |
Asset retirement obligations and other | | | 464 | | | | 465 | |
Commitments and contingencies (Note 5) | | | | | | | | |
Partners’ Capital: | | | | | | | | |
General partner’s interest | | | (2,646 | ) | | | (2,611 | ) |
Common limited partners’ interests | | | 69,652 | | | | 71,387 | |
Common limited partners’ warrants | | | 3,136 | | | | 3,136 | |
Total partners’ capital | | | 70,142 | | | | 71,912 | |
Total liabilities and partners’ capital | | $ | 72,088 | | | $ | 74,219 | |
See accompanying notes to condensed consolidated financial statements.
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ATLAS GROWTH PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
| | Three Months Ended September 30, | | | Nine Months Ended September 30, |
| | 2018 | | 2017 | | | 2018 | | 2017 |
Revenues: | | | | | | | | | | | |
Natural gas revenue | | $ | 51 | | $ | 74 | | $ | 152 | $ | 252 |
Oil revenue | | | 2,849 | | | 1,559 | | | 7,266 | | 5,467 |
NGLs revenue | | | 161 | | | 98 | | | 384 | | 282 |
Gain (loss) on mark-to-market derivatives | | (26 | ) | | (449 | ) | | (604 | ) | 942 |
Total revenues | | 3,035 | | | 1,282 | | | 7,198 | | 6,943 |
Costs and expenses: | | | | | | | | | | | |
Gas and oil production | | 663 | | | 476 | | | 2,105 | | 1,929 |
General and administrative | | 113 | | | 159 | | | 401 | | 653 |
General and administrative – affiliate | | 812 | | | 883 | | | 2,489 | | 3,248 |
Depreciation, depletion and amortization | | 1,274 | | | 825 | | | 3,973 | | 2,823 |
Total costs and expenses | | 2,862 | | | 2,343 | | | 8,968 | | 8,653 |
Net income (loss) | | $ | 173 | | $ | (1,061 | ) | $ | (1,770 | )$ | (1,710) |
Allocation of net income (loss) attributable to common limited partners and the general partner: | | | | | | | | | | | |
Common limited partners’ interest | | $ | 169 | | $ | (1,040 | ) | $ | (1,735 | )$ | (1,676) |
General partner’s interest | | 4 | | | (21 | ) | | (35 | ) | (34) |
Net income (loss) attributable to common limited partners per unit: | | | | | | | | | | | |
Basic and Diluted | | $ | 0.01 | | $ | (0.04 | ) | $ | (0.07 | )$ | (0.07) |
Weighted average common limited partner units outstanding: | | | | | | | | | | | |
Basic | | | 23,300 | | | 23,300 | | | 23,300 | | 23,300 |
Diluted | | 25,630 | | | 23,300 | | | 23,300 | | 23,300 |
See accompanying notes to condensed consolidated financial statements.
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ATLAS GROWTH PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(in thousands, except unit data)
(Unaudited)
| | General Partner’s Interest | | | Common Limited Partners’ Interests | | | Common Limited Partners’ Warrants | | | Total | |
| | Class A Units | | | Amount | | | Units | | | Amount | | | Warrants | | | Amount | | | | Partners’ Capital | |
Balance at January 1, 2018 | | | 100 | | | $ | (2,611 | ) | | | 23,300,410 | | | $ | 71,387 | | | | 2,330,041 | | | $ | 3,136 | | | $ | 71,912 | |
Net loss | | | — | | | | (19 | ) | | | — | | | | (909 | ) | | | — | | | | — | | | | (928 | ) |
Balance at March 31, 2018 | | | 100 | | | | (2,630 | ) | | | 23,300,410 | | | | 70,478 | | | | 2,330,041 | | | | 3,136 | | | | 70,984 | |
Net loss | | | — | | | | (20 | ) | | | — | | | | (995 | ) | | | — | | | | — | | | | (1,015 | ) |
Balance at June 30, 2018 | | | 100 | | | | (2,650 | ) | | | 23,300,410 | | | | 69,483 | | | | 2,330,041 | | | | 3,136 | | | | 69,969 | |
Net income | | | — | | | | 4 | | | | — | | | | 169 | | | | — | | | | — | | | | 173 | |
Balance at September 30, 2018 | | | 100 | | | $ | (2,646 | ) | | | 23,300,410 | | | $ | 69,652 | | | | 2,330,041 | | | $ | 3,136 | | | $ | 70,142 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at January 1, 2017 | | | 100 | | | $ | (2,553 | ) | | | 23,300,410 | | | $ | 74,226 | | | | 2,330,041 | | | $ | 3,136 | | | $ | 74,809 | |
Net loss | | | — | | | | (6 | ) | | | — | | | | (286 | ) | | | — | | | | — | | | | (292 | ) |
Balance at March 31, 2017 | | | 100 | | | | (2,559 | ) | | | 23,300,410 | | | | 73,940 | | | | 2,330,041 | | | | 3,136 | | | | 74,517 | |
Net loss | | | — | | | | (7 | ) | | | — | | | | (350 | ) | | | — | | | | — | | | | (357 | ) |
Balance at June 30, 2017 | | | 100 | | | | (2,566 | ) | | | 23,300,410 | | | | 73,590 | | | | 2,330,041 | | | | 3,136 | | | | 74,160 | |
Net loss | | | — | | | | (21 | ) | | | — | | | | (1,040 | ) | | | — | | | | — | | | | (1,061 | ) |
Balance at September 30, 2017 | | | 100 | | | $ | (2,587 | ) | | | 23,300,410 | | | $ | 72,550 | | | | 2,330,041 | | | $ | 3,136 | | | $ | 73,099 | |
See accompanying notes to condensed consolidated financial statements.
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ATLAS GROWTH PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
| | Nine Months Ended September 30, | |
| | 2018 | | | 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
Net loss | | $ | (1,770 | ) | | $ | (1,710 | ) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | | | | | | | | |
Depreciation, depletion and amortization | | | 3,973 | | | | 2,823 | |
(Gains) losses on derivatives | | | 271 | | | | (453 | ) |
Amortization of deferred financing costs | | | 38 | | | | 38 | |
Changes in operating assets and liabilities: | | | | | | | | |
Accounts receivable, prepaid expenses and other | | | (705 | ) | | | 27 | |
Advances to/from affiliates | | | (1,065 | ) | | | (651 | ) |
Accounts payable and accrued liabilities | | | 294 | | | | (577 | ) |
Net cash provided by (used in) operating activities | | | 1,036 | | | | (503 | ) |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Capital expenditures | | | (6,792 | ) | | | — | |
Net cash used in investing activities | | | (6,792 | ) | | | — | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
Net cash provided by (used in) financing activities | | | — | | | | — | |
Net change in cash and cash equivalents | | | (5,756 | ) | | | (503 | ) |
Cash and cash equivalents, beginning of year | | | 8,236 | | | | 8,586 | |
Cash and cash equivalents, end of period | | $ | 2,480 | | | $ | 8,083 | |
See accompanying notes to condensed consolidated financial statements.
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ATLAS GROWTH PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 – BASIS OF PRESENTATION
We are 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. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.
Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
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 and 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 condensed 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, 2017.
Principles of Consolidation
Our condensed consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the condensed consolidated financial statements as transactions between affiliates, where applicable. All intercompany transactions have been eliminated.
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 may differ from those estimates.
Derivative Instruments
We enter into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the condensed consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized in the current period within gain (loss) on mark-to-market derivatives in our condensed consolidated statements of operations.
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We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments. We manage and report derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative values were calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.
The following table summarizes the commodity derivative activity for the period indicated (in thousands):
| | | Three Months Ended
September 30, | | | Nine Months Ended September 30, | |
| | | 2018 | | 2017 | | | 2018 | | | 2017 | |
Gains (losses) recognized on cash settlement | | $ | 44 | | $ | (53 | ) | $ | (333 | ) | $ | 489 | |
Changes in fair value on open derivative contracts | | | (70 | ) | | (396 | ) | | (271 | ) | | 453 | |
Gain (loss) on mark-to-market derivatives | | $ | (26 | ) | $ | (449 | ) | $ | (604 | ) | $ | 942 | |
As of September 30, 2018, we had commodity derivatives for 17,900 barrels at an average fixed price of $52.66 which mature throughout the remaining three months of 2018. The fair value of our commodity derivatives resulted in a liability of $0.4 million as of September 30, 2018.
Segment Reporting
We derive revenue from our gas and oil production. The production facilities associated with our oil and gas production have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.
Revenue Recognition
On January 1, 2018, we adopted ASU No. 2014–09, Revenue from Contracts with Customers (the “new revenue standard”), using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. The adoption of the new revenue standard did not have a material impact on our condensed consolidated financial statements and no cumulative effect adjustment was recorded to beginning partners’ capital. As a result of adopting the new revenue standard, we disaggregated our revenues by product type on our condensed consolidated statements of operations for all periods presented.
Oil, Natural Gas, and NGL Revenues
Our revenues are derived from the sale of oil, natural gas, and NGLs, which is recognized in the period that the performance obligations are satisfied. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and the delivery of each unit represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser and title has transferred. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by us from a customer, are excluded from revenue. Payment is generally received one month after the sale has occurred.
Our oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, we generally record sales based on the net amount received.
Our natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For natural gas contracts, we generally record wet gas sales (which consists of natural gas and NGLs based on end products after processing) at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to us at the tailgate of the plant. Conversely, we generally record residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to us at the tailgate of the plant. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.
Transaction Price Allocated to Remaining Performance Obligations
9
A significant number of our product sales are short-term in nature with contract terms of one year or less, though generally subject to customary evergreen clauses pursuant to which these contracts typically automatically renew under the same terms and conditions. For those contracts, we have utilized the practical expedient allowed in the new revenue standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For product sales that have a contract term greater than one year, we have utilized the practical expedient that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Under our sales contracts, customers are invoiced once performance obligations have been satisfied, at which point our right to payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $0.9 million and $0.6 million at September 30, 2018 and December 31, 2017, respectively.
Net Income (Loss) Per Common Unit
Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners (which is determined after the deduction of the general partner’s interest) by the weighted average number of common limited partner units outstanding during the period.
The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands):
| | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30 | |
| | 2018 | | | 2017 | | 2018 | | 2017 | |
Net income (loss) | | $ | 173 | | | $ | (1,061 | ) | $ | (1,770 | ) | $ | (1,710 | ) |
Less: General partner’s interest | | | (4 | ) | | | 21 | | | 35 | | | 34 | |
Net income (loss) attributable to common limited partners | | $ | 169 | | | $ | (1,040 | ) | $ | (1,735 | ) | $ | (1,676 | ) |
Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method.
The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands):
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | | |
Weighted average number of common units – basic | | | 23,300 | | | | 23,300 | | | | 23,300 | | | | 23,300 | |
Add effect of dilutive awards(1) | | | 2,330 | | | | — | | | | — | | | | — | |
Weighted average number of common units – diluted | | | 25,630 | | | | 23,300 | | | | 23,300 | | | | 23,300 | |
(1) | For the nine months ended September 30, 2018 and the three and nine months ended September 30, 2017, 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. For the three months ended September 30, 2018, units issuable upon the exercise of the warrants are included in the computation of diluted earnings attributable to common limited partners per unit because the exercise of such warrants would have been dilutive given our net income for the period. |
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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. In January 2018, the FASB issued additional amendments to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for under current leasing guidance. An entity that elects this practical expedient should evaluate new or modified land easements beginning at the date of adoption. We do not currently account for any land easements under the current leasing guidance and plan to utilize this practical expedient in conjunction with the adoption of the updated accounting guidance related to leases. We are currently in the process of determining the impact that the updated accounting guidance will have on our condensed consolidated financial statements and will continue to monitor relevant industry guidance regarding the implementation of the standard.
NOTE 3 – PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
| | September 30, 2018 | | December 31, 2017 | |
Natural gas and oil properties: | | | | | | | |
Proved properties | | $ | 154,803 | | $ | 147,932 | |
Support equipment and other | | | 3,188 | | | 3,188 | |
| | | 157,991 | | | 151,120 | |
Less – accumulated depreciation, depletion and amortization | | | (89,792 | ) | | (85,827 | ) |
| | $ | 68,199 | | $ | 65,293 | |
During the nine months ended September 30, 2018, we deployed $6.8 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line in May 2018. During the nine months ended September 30, 2018 and 2017, we did not have any material non-cash investing activity capital expenditures.
NOTE 4 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Relationship with ATLS. We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates, including Titan Energy, LLC (“Titan”). Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During both of the three months ended September 30, 2018 and 2017, we paid a management fee of $0.6 million to our general partner; during both of the nine months ended September 30, 2018 and 2017 we paid a management fee of $1.7 million to our general partner. Other indirect costs, such as rent for offices, are allocated by Titan at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and our general partner discussed above were included in general and administrative expenses – affiliate in the condensed consolidated statements of operations. As of September 30, 2018 and December 31, 2017, we had payables to ATLS of zero and $0.6 million, respectively, related to the management fee, direct costs and allocated indirect costs, which were recorded in advances from affiliates in the condensed consolidated balance sheets.
Relationship with Titan. At the direction of ATLS, we reimburse Titan for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. As of September 30, 2018 and December 31, 2017, we had receivables from Titan of $0.5 million and payables to Titan of $0.1 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for reimbursement of operating activities and capital expenditures, which were recorded in advances to/from affiliates in the condensed consolidated balance sheets.
NOTE 5 – COMMITMENTS AND CONTINGENCIES
General Commitments
As of September 30, 2018, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits to such executives. The agreements provide for severance payments under certain circumstances.
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As of September 30, 2018, we did not have any commitments related to our drilling and completion and capital expenditures.
Legal Proceedings
We and our subsidiaries are parties to various routine legal proceedings arising in 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 and our subsidiaries 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 and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of September 30, 2018 or December 31, 2017.
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ITEM 2: | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
BUSINESS OVERVIEW
We are 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. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and controls us.
Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner.
MANAGEMENT OVERVIEW AND OUTLOOK
Since our inception in 2013, we have developed into a company with a core position in the Eagle Ford Shale in South Texas generating stable cash flows, despite a significant decline in oil and natural gas prices. While the energy markets continue to be marked by volatility, we are focused on refining our operations to reduce expenses. As September 30, 2018, we have $2.5 million of cash on our balance sheet and no long-term debt.
During the nine months ended September 30, 2018, we deployed $6.8 million of cash on hand to drill and complete one Eagle Ford Shale well that turned in-line during May 2018. The well is expected to significantly increase our production and provide substantial cash flow. With this additional well, we have enhanced ability to generate positive cash flow from our operations, grow our cash balance, and take advantage of opportunities to drill new Eagle Ford Shale wells or take on other strategic initiatives and transactions should favorable conditions arise.
While we manage the company on a daily basis to optimize operating results, we also continue to explore ways to strategically grow and transform the company. Quarterly, we consider our ability to make distributions to unitholders; however, based on the company’s financial position and cash flows, we have not yet elected to resume making distributions following the suspension in November 2016. We continue to explore opportunities to drill additional wells across our Eagle Ford Shale locations. Our ability to convert our locations into cash-flowing wells may be improved by raising additional capital, but we have limited avenues to do so at this time. We continue to evaluate the most attractive way to accelerate growth of our portfolio and drive value to all of our equity holders. We will continue to vigorously pursue all options to maximize returns to our investors.
GENERAL TRENDS AND OUTLOOK
We expect our business to be affected by key trends in natural gas and oil production markets. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Throughout 2017 and 2018, the natural gas, oil and natural gas liquids commodity price markets have been marked by volatility. While we anticipate 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. The economics of drilling new oil wells across our acreage position in the Eagle Ford Shale in South Texas have improved substantially over the last twelve months, driven by both a rise in oil prices, as well as significant advancements in drilling and completion technology.
Our future gas and oil reserves, production, cash flow, our ability to make payments on our obligations and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently, developing our existing acreage and acquiring additional proved reserves economically. We 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. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. To the extent we would not have access to sufficient capital, our ability to drill and acquire more reserves would be negatively impacted.
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RESULTS OF OPERATIONS
Gas and Oil Production
Production Profile. We have established production positions in the following areas:
| • | the Eagle Ford Shale in South Texas, an oil-rich area, in which we acquired acreage in November 2014, where we derive over 96% of our production volumes and revenues; |
| • | the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, which contains liquids-rich natural gas and oil; and |
| • | the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area. |
The following table presents the number of wells we drilled and the number of wells we turned in line, both gross and net during the periods indicated:
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | |
Gross wells drilled(1) | | | — | | | | — | | | | 1 | | | | — | |
Net wells drilled(1) | | | — | | | | — | | | | 1 | | | | — | |
Gross wells turned in line(2) | | | — | | | | — | | | | 1 | | | | — | |
Net wells turned in line(2) | | | — | | | | — | | | | 1 | | | | — | |
(1) | There were no exploratory wells drilled during each of the periods presented. |
(2) | Wells turned in line refers to wells that have been drilled, completed and connected to a gathering system. |
Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production volumes per day for the periods indicated:
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | |
Total production volumes per day:(1) | | | | | | | | | | | | | | | | |
Natural gas (Boed) | | | 54 | | | | 50 | | | | 50 | | | | 53 | |
Oil (Bpd) | | | 431 | | | | 359 | | | | 387 | | | | 415 | |
NGLs (Bpd) | | | 62 | | | | 52 | | | | 56 | | | | 55 | |
Total (Boed) | | | 548 | | | | 462 | | | | 494 | | | | 522 | |
Total production volumes:(1) | | | | | | | | | | | | | | | | |
Natural gas (MBoe) | | | 5 | | | | 5 | | | | 14 | | | | 14 | |
Oil (MBbls) | | | 40 | | | | 33 | | | | 105 | | | | 113 | |
NGLs (MBbls) | | | 6 | | | | 5 | | | | 15 | | | | 15 | |
Total (MBoe) | | | 50 | | | | 43 | | | | 135 | | | | 143 | |
(1) | “MBbls” represents one thousand barrels; “Boe” and “MBoe” represent barrel equivalent and one thousand barrel equivalents; “Boed” represents barrels per day; “and “Bbls” and “Bpd” represent barrels and barrels per day. Mcfe are converted to barrels using the ratio of approximately 6 Mcf to one barrel. |
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Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for oil. The following table presents our production revenues and average sales prices for our natural gas, oil, and natural gas liquids production, along with our average production costs, which include lease operating expenses, taxes, and transportation and compression costs, for the periods indicated:
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | |
Production revenues (in thousands): | | | | | | | | | | | | | | |
Natural gas revenue | | $ | 51 | | | $ | 74 | | $ | 152 | | $ | 252 | |
Oil revenue | | 2,849 | | | | 1,559 | | | 7,266 | | | 5,467 | |
NGLs revenue | | 161 | | | | 98 | | | 384 | | | 282 | |
Total production revenues | | $ | 3,061 | | | $ | 1,731 | | $ | 7,802 | | $ | 6,001 | |
Average sales price, unhedged: | | | | | | | | | | | | | | |
Natural gas (per Mcf) | | $ | 1.74 | | | $ | 2.69 | | $ | 1.86 | | $ | 2.92 | |
Oil (per Bbl) | | $ | 70.93 | | | $ | 47.16 | | $ | 68.40 | | $ | 48.30 | |
NGLs (per Bbl) | | $ | 28.41 | | | $ | 20.30 | | $ | 25.13 | | $ | 18.79 | |
| | | | | | | | | | | | | | |
Total Gas and Oil Costs (in thousands) | | $ | 663 | | | $ | 476 | | $ | 2,105 | | $ | 1,929 | |
| | | | | | | | | | | | | | |
Total Production costs (per Boe): | | | | | | | | | | | | | | |
Lease operating expenses | | $ | 9.43 | | | $ | 7.98 | | $ | 11.77 | | $ | 10.22 | |
Production taxes | | 3.14 | | | | 3.54 | | | 3.35 | | | 3.10 | |
Transportation and compression | | 0.34 | | | | 0.35 | | | 0.24 | | | 0.34 | |
Total production costs per Boe | | $ | 12.90 | | | $ | 11.87 | | $ | 15.36 | | $ | 13.65 | |
Our gas and oil production revenues were higher in the current quarter as compared to the prior year period due to a $1.1 million increase related to production from an additional well turned in line during May 2018, a $0.5 million increase due to higher realized average oil sales prices and a $0.1 million increase in natural gas liquids prices, partially offset by a $0.4 million decrease in oil production volumes from existing wells. Our gas and oil production revenues were higher in the nine months ended September 30, 2018 as compared to the prior year period due to a $2.1 million increase related to production from an additional well turned in line during May 2018, a $1.5 million increase due to higher realized oil average sales prices and a $0.1 million increase in natural gas liquids prices, partially offset by a $1.8 million decrease in oil production volumes from existing wells and a $0.1 million decrease in gas prices.
Our gas and oil production costs were higher in the current quarter and nine months ended September 30, 2018 compared to the corresponding periods from the prior year due to a $0.2 million increase in production costs in the Eagle Ford Shale due to our well that turned in-line during May 2018.
OTHER REVENUES AND EXPENSES
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
(in thousands) | | 2018 | | | 2017 | | | 2018 | | | 2017 | |
| | | | | | | | | | | | | | |
Other Revenues | | | | | | | | | | | | | | |
Gain (loss) on mark-to-market derivatives | | $ | (26 | ) | | $ | (449 | ) | $ | (604 | ) | $ | 942 | |
| | | | | | | | | | | | | | |
Other Expenses | | | | | | | | | | | | | | |
General and administrative | | $ | 925 | | | $ | 1,042 | | $ | 2,890 | | $ | 3,901 | |
Depreciation, depletion and amortization | | | 1,274 | | | | 825 | | | 3,973 | | | 2,823 | |
Gain (loss) on Mark-to-Market Derivatives. We recognize changes in fair value of derivatives immediately within gain (loss) on mark-to-market derivatives on our condensed consolidated statements of operations. The recognized gains/(losses) during the three and nine months ended September 30, 2018 and 2017 were due to changes in commodity futures prices relative to our derivative positions as of the respective prior period end.
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General and Administrative Expenses. The decrease in general and administrative expenses for the current quarter and the nine months ended September 30, 2018 as compared to the prior year periods was due to decreases of $0.1 million and $1.0 million, respectively, in salaries, wages and other corporate activity costs allocated to us as a result of lower corporate activities.
Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization for the current period and the nine months ended September 30, 2018 as compared to the prior year periods was due to a $0.4 million and $1.2 million increase, respectively, in our depletion expense in the Eagle Ford Shale due to the additional well that turned in-line in May 2018.
LIQUIDITY AND CAPITAL RESOURCES
General
We currently fund our operations through cash generated from operations. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas remain volatile but have improved during 2018 as compared to the prior year.
As of September 30, 2018, we have $2.5 million of cash on our balance sheet and no long-term debt.
Cash Flows
| | Nine Months Ended September 30, | |
| | | 2018 | | | | 2017 | |
Net cash provided by (used in) operating activities | | $ | 1,036 | | | $ | (503 | ) |
Net cash used in investing activities | | | (6,792 | ) | | | — | |
Net cash used in financing activities | | | — | | | | — | |
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Nine Months Ended September 30, 2018 Compared with the Nine Months Ended September 30, 2017
Cash Flows from Operating Activities:
The change in cash flows provided by (used in) operating activities compared with the prior period was due to:
| • | an increase of $3.0 million net cash provided by operating activities from cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production revenues, and collections net of payments for royalties, lease operating expenses, severance taxes and general and administrative expenses; partially offset by |
| • | an increase of $0.4 million net cash used in operating activities from advances from affiliates related to the direct costs, indirect cost allocation, and timing of funding of cash accounts for reimbursement of operating activities and capital expenditures; and |
| • | an increase of $1.1 million net cash used in operating activities related to cash settlement payments on our commodity derivative contracts. |
Cash Flows from Investing Activities:
The change in cash flows used in investing activities compared with the prior year period was due to an increase of $6.8 million in capital expenditures related to our development activities as we drilled and brought in line a well in the Eagle Ford Shale during May 2018.
Capital Requirements
During the nine months ended September 30, 2018, our capital expenditures were $6.8 million, related to our well drilling and completion costs. As of September 30, 2018, we did not have any material accrued well drilling and completion and capital expenditures.
The capital expenditures of our natural gas and oil production assets primarily consist of discretionary expenditures to maintain or increase production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures.
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, 2017.
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, 2017.
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, 2017.
Recently Issued Accounting Standards
See “Item 1: Financials Statements – Note 2” 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 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 view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.
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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 September 30, 2019. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our business.
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 net income for the twelve-month period ending September 30, 2019 of $0.7 million.
Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years.
As of September 30, 2018, we had the following commodity derivatives:
Crude Oil – Fixed Price Swaps
Production Period Ending December 31, | | Volumes | | | Average Fixed Price | |
| | (Bbl)(1) | | | (per Bbl)(1) | |
2018(2) | | | 17,900 | | | $ | 52.66 | X |
(1)“Bbl” represents barrels.
(2)The production volumes for 2018 include the remaining three months of 2018 beginning October 1, 2018.
ITEM 4: | CONTROLS AND PROCEDURES |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer (principal executive officer) and our Chief Financial Officer (principal financial officer) has evaluated the effectiveness of our disclosure controls and procedures in ensuring that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including ensuring that such information is accumulated and communicated to management (including the principal executive and financial officers) as appropriate to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive and financial officers have concluded that such disclosure controls and procedures were effective as of September 30, 2018.
Changes in Internal Control over Financial Reporting
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.
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PART II
(1) | 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 GROWTH PARTNERS, L.P. |
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By: Atlas Growth Partners GP, LLC, its General Partner |
| |
| | | | |
Date: November 19, 2018 | | By: | | /s/ EDWARD E. COHEN |
| | | | Edward E. Cohen Chairman of the Board and Chief Executive Officer |
| | | | |
Date: November 19, 2018 | | By: | | /s/ JEFFREY M. SLOTTERBACK |
| | | | Jeffrey M. Slotterback Chief Financial Officer |
| | | | |
Date: November 19, 2018 | | By: | | /s/ MATTHEW J. FINKBEINER |
| | | | Matthew J. Finkbeiner Chief Accounting Officer |
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