Atlas Resources Public #18-2009 10Q 2017 Q3 Quarterly report

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, 2017

☐	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 333-150925-01

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

(Name of small business issuer in its charter)

Delaware		27-0213766
(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)

Issuer’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 (§232.405 of this chapter) 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 ☒

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

(A Delaware Limited Partnership)

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of September 30, 2017 and December 31, 2016	3
	Condensed Statements of Operations for the Three and Nine Months ended September 30, 2017 and 2016	4
	Condensed Statements of Comprehensive Income (Loss) for the Three and Nine Months ended September 30, 2017 and 2016	5
	Condensed Statement of Changes in Partners’ Capital for the Nine Months ended September 30, 2017	6
	Condensed Statements of Cash Flows for the Nine Months ended September 30, 2017 and 2016	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 4:	Controls and Procedures	20
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	21
Item 6:	Exhibits	22
SIGNATURES		23
CERTIFICATIONS

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30, 2017			December 31, 2016
	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash	$	324,500		$	254,600
Accounts receivable trade–affiliate		66,000			83,300
Current assets held for sale (Note 3)					1,139,500
Total current assets		390,500			1,477,400
Gas and oil properties, net		1,614,400			1,770,200
Long-term asset retirement receivable-affiliate		100,500			46,200
Non-current assets held for sale (Note 3)					31,075,100
Total assets	$	2,105,400		$	34,368,900

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	17,200		$	18,500
Current liabilities held for sale (Note 3)					39,700
Total current liabilities		17,200			58,200
Asset retirement obligations		751,300			732,500
Non-current liabilities held for sale (Note 3)		-			2,641,800
Commitments and contingencies (Note 5)
Partners’ capital:
Managing general partner’s interest		(341,500	)		2,201,400
Limited partners’ interest (22,928.90 units)		1,678,400			28,735,000
Total partners’ capital		1,336,900			30,936,400
Total liabilities and partners’ capital	$	2,105,400		$	34,368,900

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
REVENUES
Natural gas	$	191,900		$	230,700		$	565,000		$	540,200
Gain on mark-to-market derivatives		-			5,700			-			7,500
Total revenues		191,900			236,400			565,000			547,700
COSTS AND EXPENSES
Production		193,700			218,900			465,600			630,000
Depletion		56,200			27,600			155,800			78,000
Accretion of asset retirement obligations		6,300			6,100			18,800			18,200
General and administrative		3,100			4,000			9,100			12,000
Total costs and expenses		259,300			256,600			649,300			738,200
Net loss from continuing operations		(67,400)			(20,200)			(84,300)			(190,500)
Net income (loss) from discontinued operations		318,900			(1,100)			1,842,600			(435,100)
Net income (loss)	$	251,500		$	(21,300)		$	1,758,300		$	(625,600)
Allocation of net income (loss):
Managing general partner	$	170,200		$	116,700		$	801,200		$	227,400
Limited partners	$	81,300		$	(138,000	)	$	957,100		$	(853,000	)
Net income (loss) from continuing operations per limited partnership unit	$	(1	)	$	(6	)	$	(2	)	$	(11	)
Net income (loss) from discontinued operations per limited partnership unit	$	5		$	-		$	44		$	(26	)

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
Net income (loss)	$	251,500	$	(21,300	)	$	1,758,300	$	(625,600	)
Other comprehensive loss:
Difference in estimated hedge receivable		-		68,000			-		196,600
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		-		(68,200	)		-		(197,100	)
Total other comprehensive loss		-		(200	)		-		(500	)
Comprehensive income (loss)	$	251,500	$	(21,500	)	$	1,758,300	$	(626,100	)

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ (DEFICIT) CAPITAL

(Unaudited)

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2016	$	2,201,400		$	28,735,000		$	30,936,400
Participation in revenues, costs and expenses:
Net production revenues		27,800			71,600			99,400
Depletion		(33,500	)		(122,300	)		(155,800	)
Accretion of asset retirement obligations		(5,200	)		(13,600	)		(18,800	)
General and administrative		(2,500	)		(6,600	)		(9,100	)
Net income (loss) from continuing operations		(13,400	)		(70,900	)		(84,300	)

Participation in net income from discontinued operations		816,100			1,026,500			1,842,600
Distributions to partners		(897,400	)		(2,448,500	)		(3,345,900	)

Transfer of interests to DGOC Series 18(C), L.P. (Note 2)		(2,448,200	)		(25,563,700	)		(28,011,900	)
Balance at September 30, 2017	$	(341,500	)	$	1,678,400		$	1,336,900

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	1,758,300		$	(625,600	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (income) loss from discontinued operations………………………………………………		(1,842,600	)		435,100
Depletion		155,800			78,000
Non-cash loss on derivative value		-			57,000
Accretion of asset retirement obligations		18,800			18,200
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate		17,300			(48,600	)
Increase in asset retirement receivable-affiliate		(54,300	)		(12,000	)
(Decrease) increase in accrued liabilities		(1,300	)		600
Net cash provided by (used in) continuing operating activities		52,000			(97,300	)
Net cash provided by discontinued operating activities		3,363,800			2,315,600
Net cash provided by operating activities		3,415,800			2,218,300
Cash flows from investing activities:
Net cash provided by (used in) continuing investing activities		-			-
Net cash provided by (used in) discontinued investing activities		-			-
Net cash provided by (used in) investing activities		-			-
Cash flows from financing activities:
Distributions to partners		(3,345,900	)		(2,131,000	)
Net cash used in financing activities		(3,345,900	)		(2,131,000	)
Net change in cash		69,900			87,300
Cash at beginning of period		254,600			170,900
Cash at end of period	$	324,500		$	258,200

See accompanying notes to condensed financial statements.

ATLAS RESOURCES PUBLIC #18-2009 (C) L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

Atlas Resources Public #18-2009 (C) L.P. is a Delaware limited partnership, formed on June 9, 2009 with Atlas Resources, LLC serving as its Managing General Partner (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Titan Energy, LLC (“Titan”; OTCQX: TTEN). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas Resources Public #18-2009 (C) L.P.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan.

The Partnership drilled wells located in Pennsylvania, Tennessee and Indiana and currently operates the wells in Indiana. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas. Produced natural gas is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.

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

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had been adequate to fund its obligations and distributions to its partners. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continue to remain low in 2017. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be strategic in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the liquidation of the Partnership’s operations.

The uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which also raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended.

If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and could occur without any further contributions from or distributions to the limited partners.

The 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. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.

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

The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for debt service including interest, and capital expenditures.

The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under Titan’s credit facilities and equity and debt offerings. The MGP’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 continue to remain low in 2017. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities.

Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern.

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility. The amendment provides for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales of non-core assets, which include the sale of its Appalachian and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien credit facility. Titan’s strategy is to continue to sell non-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

On April 21, 2017, the lenders under the Titan’s second lien credit facility delivered a notice of events of default and reservation of rights, pursuant to which they noticed events of default related to financial covenants and the failure to deliver financial statements without a “going concern” qualification. The delivery of such notice began the 180-day standstill period under the intercreditor agreement, during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility. The lenders have not accelerated the payment of amounts outstanding under the second lien credit facility.

On May 4, 2017, Titan entered into a definitive purchase and sale agreement (the “Purchase Agreement”) to sell its conventional Appalachia and Marcellus assets to Diversified Gas & Oil, PLC (“Diversified”), for $84.2 million. The transaction includes the sale of approximately 8,400 oil and gas wells across Pennsylvania, Ohio, Tennessee, New York and West Virginia, along with the associated infrastructure (the “Appalachian Assets”). On June 30, 2017, Titan completed a majority of the Appalachian Assets sale for net cash proceeds of $65.6 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility. Effective on June 30, 2017, the MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania and Tennessee.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million, which included customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirements to reduce its first lien credit facility borrowings below $360 million as required by August 31, 2017.

On September 27, 2017, the lenders under Titan’s second lien credit facility entered into a letter agreement with Titan and its lenders under the first lien credit facility (the “Extension Letter”). Pursuant to the Extension Letter, the second lien credit facility lenders agreed to extend the 180-day standstill period under the intercreditor agreement (during which the lenders under the second lien credit facility are prevented from pursuing remedies against the collateral securing Titan’s obligations under the second lien credit facility) by an additional 35 days from October 18, 2017 to November 22, 2017. In addition, the extension of the standstill period extends the waiver of certain defaults under the first lien credit facility, which terminates 15 business days prior to the expiration of the standstill period. The parties agreed to extend the standstill period to provide Titan with additional time to negotiate proposed amendments to each of the first lien credit facility and the second lien credit facility.

Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its 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 Titan’s stakeholders.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed 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 results of operations, financial condition and cash flows for the periods shown, including normal, recurring accruals and other items. The results of operations for the interim periods presented are not necessarily indicative of results for the full year. The year-end condensed 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 financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

Titan’s Appalachia Divestiture

Among other things, the Purchase Agreement included the sale of Titan’s indirect interests in the assets and liabilities associated with the Partnership’s natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC Series 18(C), L.P., a newly formed entity and former subsidiary of the Partnership (“DGOC”), for which Atlas Resources served as its managing general partner. We refer to this transfer as the “separation.”

On September 29, 2017, the separation was accomplished through a transaction in which all of the natural gas and oil development and production assets of the Partnership located in Pennsylvania and Tennessee were transferred to DGOC. After the separation, the Partnership distributed to its unit holders, on a pro rata basis, common units representing one hundred percent of the limited partner interest in DGOC. In connection with the completion of the separation and distribution, the MGP transferred its limited partner and general partner interests in DGOC (the “DGOC equity interests”) to DGOC Partnership Holdings II, LLC (“DGOC Holdings”) formed as a wholly owned subsidiary of Titan to serve as DGOC’s new managing general partner (the “DGOC MGP”). Following the completion of the separation and distribution and the transfer of the DGOC equity interests to the DGOC MGP, the equity interests of the DGOC MGP were transferred to Diversified and Diversified owns the managing general partner of the DGOC.

Use of Estimates

The preparation of the Partnership’s condensed 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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s condensed financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s condensed financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, impairments, fair value of derivative instruments and the probability of forecasted transactions. The natural 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.

Derivative Instruments

The Partnership’s MGP entered into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives were recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. During the three and nine months ended September 30, 2017, the Partnership did not have any derivative activity as all derivative contracts have matured. During the three and nine months ended September 30, 2016, the Partnership recorded gains of $5,700 and $7,500, respectively subsequent to hedge accounting recognized in gain on mark-to-market derivatives on the condensed statements of operations.

Discontinued Operations

A disposal of a component of our entity is classified as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on our operations and financial results. For components classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the condensed balance sheet and to net income (loss) from discontinued operations on the condensed statement of operations for all periods presented. See Note 3 for additional disclosures regarding discontinued operations.

Gas and Oil Properties

The following is a summary of gas and oil properties at the dates indicated:

	September 30, 2017			December 31, 2016
	September 30, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	1,059,400		$	1,059,400
Wells and related equipment		29,450,800			29,450,800
Total natural gas and oil properties		30,510,200			30,510,200
Accumulated depletion and impairment		(28,895,800	)		(28,740,000	)
Gas and oil properties, net	$	1,614,400		$	1,770,200

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 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. We have made progress on our contract reviews and documentation. Substantially all of our revenue is earned pursuant to agreements under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. We are currently unable to reasonably estimate the expected financial statement impact; however, we do not believe the new accounting guidance will have a material impact on our financial position, results of operations or cash flows. We intend to adopt the new accounting guidance using the modified retrospective method. The new 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.

NOTE 3 – DISCONTINUED OPERATIONS

As disclosed in Note 2, on September 29, 2017, Titan completed the remainder of the Appalachia Assets sale, which included the sale of Titan’s indirect interests in the assets and liabilities associated with the Partnership’s natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC.

The Partnership determined that the natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC represent discontinued operations as they constitute a disposal of a group of components and a strategic shift that will have a major effect on the Partnership’s operations and financial results. As a result, the Partnership reclassified the balances and activities of its natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC from their historical presentation to assets and liabilities held for sale on the condensed balance sheet and to net income (loss) from discontinued operations on the condensed statement of operations for all periods presented. Our financial results and cash flows for future periods following the separation, including the Partnership’s ability to make distributions, will be different from historical trends and the differences may be material.

The following table reconciles the major classes of line items from the Partnership’s natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC classified as discontinued operations included within net income (loss) from discontinued operations for the periods presented, in thousands:

	Three Months Ended September 30,					Nine Months Ended September 30,

	2017		2016			2017		2016
Revenues:
Natural gas and oil	$	1,354,900	$	1,122,800		$	5,176,600	$	3,222,400
Gain on mark-to-market derivatives		-		9,200			-		14,200
Total revenues		1,354,900		1,132,000			5,176,600		3,236,600

Costs and expenses:
Production	$	471,000	$	459,400		$	1,579,600	$	1,548,500
Depletion		500,900		607,500			1,559,800		1,923,200
Accretion of asset retirement obligations		32,900		31,200			98,600		93,700
General and administrative		31,200		35,000			96,000		106,300
Total costs and expenses	$	1,036,000	$	1,133,100		$	3,334,000	$	3,671,700
Net income (loss) from discontinued operation	$	318,900	$	(1,100	)	$	1,842,600	$	(435,100	)

The following table details the major classes of assets and liabilities of the Partnership’s natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC on September 29, 2017 and were classified as held for sale at December 31, 2016:

	December 31,
	2016

Accounts receivable trade-affiliate		1,139,500
Total current assets of discontinued operations held for sale		1,139,500

Gas and oil properties, net		30,904,400
Long-term asset retirement receivable-affiliate		170,700
Total non-current assets of discontinued operations held for sale		31,075,100
Total assets classified as held for sale	$	32,214,600

Accounts payable trade-affiliate	$	39,700
Total current liabilities of discontinued operations held for sale		39,700

Asset retirement obligations		2,641,800
Total non-current liabilities of discontinued operations held for sale		2,641,800
Total liabilities classified as held for sale	$	2,681,500

NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s condensed statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expenses in the Partnership’s condensed statements of operations, are payable at $1,500 per well per month for New Albany wells for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s condensed statements of operations and are generally payable at 16% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s condensed statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

The following table provides information with respect to these costs and the periods incurred:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Administrative fees	$	1,600	$	1,900	$	4,400	$	6,000
Supervision fees		30,800		36,700		87,500		119,200
Transportation fees		7,600		5,000		11,600		15,000
Direct costs		156,800		179,300		371,200		501,800
Total	$	196,800	$	222,900	$	474,700	$	642,000

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

NOTE 5 - COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2017, the MGP withheld $100,500 of net production revenue for future plugging and abandonment costs. The decision by the MGP to withhold funds for plugging and abandonment may affect the ability of the Partnership to make distributions to partners in future periods. Effective on June 30, 2017, the MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania and Tennessee.

Legal Proceedings

The Partnership and affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising out of the ordinary course of its business. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s or the MGP’s financial condition or results of operations.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

General

Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan.

We drilled wells located in Pennsylvania, Tennessee, and Indiana and currently operate the wells in Indiana. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

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

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

On April 19, 2017, Titan entered into a third amendment to its first lien credit facility. The amendment provides for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. As part of its overall business strategy, Titan has continued to execute on sales of non-core assets, which included the sale of its Appalachia and Rangely operations. The proceeds of the consummated asset sales were used to repay borrowings under its first lien

credit facility. Titan’s strategy is to continue to sell non-core assets to reduce its leverage position, which will also help Titan to comply with the requirements of its first lien credit facility amendment.

On June 12, 2017, Titan entered into a definitive agreement to sell its 25% interest in Rangely Field to an affiliate of Merit Energy Company, LLC for $105 million. On August 7, 2017, Titan completed the sale of Rangely Field for net cash proceeds of $103.5 million subject to customary preliminary purchase price adjustments, all of which was used to repay a portion of the outstanding indebtedness under its first lien credit facility and achieve compliance with the requirement to reduce its first lien credit facility borrowings below $360 million, as required by August 31, 2017.

On September 29, 2017, Titan completed the remainder of the Appalachia Assets sale for additional cash proceeds of $10.4 million, all of which was used to repay a portion of outstanding borrowings under its first lien credit facility.Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its 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 Titan’s stakeholders.

Titan’s Appalachia Divestiture

Overview

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

•

well tending, routine maintenance and adjustment;

•

reading meters, recording production, pumping, maintaining appropriate books and records; and

•

preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of September 30, 2017, our MGP withheld $100,500 of net production revenues for this purpose. The decision by the MGP to withhold funds for plugging and abandonment may affect the ability of the Partnership to make distributions to partners in future periods. Effective on June 30, 2017, the MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania and Tennessee.

Markets and Competition

The availability of a ready market for natural gas produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas in interstate commerce, other governmental regulation of the production and transportation of natural gas and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2017 and 2016, we experienced no problems in selling our natural gas. Product availability and price are the principal means of competing in selling natural gas production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

Results of Operations

Discontinued operations. The Partnership determined that the natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC represent discontinued operations as they constitute a disposal of a group of components and a strategic shift that will have a major effect on the Partnership’s operations and financial results. As a result, the Partnership reclassified the balances and activities of its natural gas and oil wells in Pennsylvania and Tennessee that were transferred to DGOC from their historical presentation to assets and liabilities held for sale on the condensed balance sheet and to net income (loss) from discontinued operations on the condensed statement of operations for all periods presented. Our financial results and cash flows for future periods following the separation, including the Partnership’s ability to make distributions, will be different from historical trends and the differences may be material.

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Production revenues (in thousands):
Gas	$	192		$	231		$	565		$	540

Production volumes:
Gas (mcf/day)⁽¹⁾		694			793			649			807

Average sales prices:
Gas (per mcf) ⁽¹⁾	$	3.00		$	2.84		$	3.19		$	2.35

Production costs:
As a percent of revenues		101	%		95	%		82	%		117	%
Per mcfe⁽¹⁾	$	3.03		$	2.69		$	2.63		$	2.74

Depletion per mcfe	$	0.88		$	0.34		$	0.88		$	0.34

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbl” represents barrels. Bbl is converted to mcfe using the ratio of nine mcfs to one bbl.

Revenues

The following tables reconcile the changes in natural gas revenues for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.

	Three Months Ended September 30,
			Natural gas
Revenues for the three months ended September 30, 2016		$	230,700
Volume decrease			(49,400	)
Price increase			10,600
Net decrease			(38,800	)
Revenues for the three months ended September 30, 2017		$	191,900

	Nine Months Ended September 30,
			Natural gas
Revenues for the nine months ended September 30, 2016		$	540,200
Volume decrease			(124,000	)
Price increase			148,800
Net increase			24,900
Revenues for the nine months ended September 30, 2017		$	565,000

The natural gas volume variances reflected for the periods presented in the tables above relate to (1) wells being temporarily shut-in, (2) which may result in timing differences associated with the production from those wells depending upon when they are placed back into production, and (3) normal and expected declines inherent in the life of a well.

Gain on Mark-to-Market Derivatives. We recognized changes in the fair value of our derivatives immediately within gain on mark-to-market derivatives on our condensed statements of operations. As of December 31, 2016, all derivative contracts have matured and we have not entered into any new contracts.

We recognized a gain on mark-to-market derivatives of $5,700 and $7,500 for the three and nine months ended September 30, 2016, respectively. These changes were due to mark-to-market gains primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $193,700 and $218,900 for the three months ended September 30, 2017 and 2016, respectively, a decrease of $25,200 (12%). Production expenses were $465,600 and $630,000 for the nine months ended September 30, 2017 and 2016, respectively, a decrease of $164,400 (26%). The decrease for the three months ended September 30, 2017 when compared to the prior year similar period was mainly a result of a decrease in supervision fees and direct costs. The decrease for the nine months ended September 30, 2017 when compared to the prior year similar period was mostly attributable to decreases in water hauling and disposal costs as a result of managing well pressures and reducing water production, compressor station expenses as a result of a decrease in production volumes and supervision fees.

Depletion of gas and oil properties as a percentage of gas and oil revenues was 29% and 12% for the three months ended September 30, 2017 and 2016, respectively, and 28% and 14% for the nine months ended September 30, 2017 and 2016, respectively. This change was primarily attributable to changes in revenues from product prices and production volumes, gas reserve quantities, and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses for the three months ended September 30, 2017 and 2016 were $3,100 and $4,000, respectively, a decrease of $900 (23%). For the nine months ended September 30, 2017 and 2016, these expenses were $9,100 and $12,000, respectively, a decrease of $2,900 (24%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs charged to us and services provided to us.

Cash Flows Overview. Cash flows from continuing operating activities consists of $52,000 and ($97,300) for the nine months ended September 30, 2017 and 2016, respectively, of net cash provided by (used in) continuing operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production, lease operating expenses, gathering, processing and transportation expenses, severance taxes, general and administrative expenses.

There was no cash provided by continuing investing activities for the nine months ended September 30, 2017 and 2016.

Cash used in financing activities consists of $3,345,900 and $2,131,000 for the nine months ended September 30, 2017 and 2016 respectively. This increase was due to greater distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through September 30, 2017, our MGP withheld $100,500 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

Critical Accounting Policies

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

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed 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.

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s 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 general partner’s 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 general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2017, our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes in the Partnership’s 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 OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

ITEM 6.

EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description

31.1		Certification Pursuant to Rule 13a-14/15(d)-14

31.2		Certification Pursuant to Rule 13a-14/15(d)-14

32.1		Section 1350 Certification

32.2		Section 1350 Certification

101		Interactive Data File

SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Atlas Resources Public #18-2009 (C) L.P.

	By:	Atlas Resources, LLC, its
		Managing General Partner

Date: November 20, 2017	By:	/s/ FREDRICK M. STOLERU
		Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)

Date: November 20, 2017

By:

/s/ JEFFREY M. SLOTTERBACK

Jeffrey M. Slotterback

Chief Financial Officer of the

Managing General Partner

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Readability	H.S. junior Bad

Atlas Resources Public #18-2009 Inactive 10-Q2017 Q3 Quarterly report

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