pub18c-10q_20170331.htm

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.

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 ☒

	March 31, 2017		December 31, 2016
	March 31, 2017		December 31, 2016
ASSETS
Current assets:
Cash	$	490,600	$	254,600
Accounts receivable trade–affiliate		1,840,200		1,222,800
Total current assets		2,330,800		1,477,400
Gas and oil properties, net		32,085,400		32,674,600
Long-term asset retirement receivable-affiliate		236,500		216,900
Total assets	$	34,652,700	$	34,368,900

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	52,200	$	58,200
Total current liabilities		52,200		58,200
Asset retirement obligations		3,413,400		3,374,300
Commitments and contingencies (Note 4)
Partners’ capital:
Managing general partner’s interest		2,407,500		2,201,400
Limited partners’ interest (22,928.90 units)		28,779,600		28,735,000
Total partners’ capital		31,187,100		30,936,400
Total liabilities and partners’ capital	$	34,652,700	$	34,368,900

	Three Months Ended
	March 31,
	2017		2016
REVENUES
Natural gas	$	2,210,400	$	1,198,300
Gain on mark-to-market derivatives		-		174,600
Total revenues		2,210,400		1,372,900
COSTS AND EXPENSES
Production		686,400		847,100
Depletion		589,200		725,000
Accretion of asset retirement obligations		39,100		37,300
General and administrative		35,100		39,600
Total costs and expenses		1,349,800		1,649,000
Net income (loss)	$	860,600	$	(276,100	)
Allocation of net income (loss):
Managing general partner	$	347,100	$	22,400
Limited partners	$	513,500	$	(298,500	)
Net income (loss) per limited partnership unit	$	22	$	(13	)

	Three Months Ended
	March 31,
	2017		2016
Net income (loss)	$	860,600	$	(276,100	)
Other comprehensive loss:
Less: reclassification adjustment to net income (loss) of mark-to-market gains on cash flow hedges		-		(200	)
Total other comprehensive loss		-		(200	)
Comprehensive income (loss)	$	860,600	$	(276,300	)

	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		425,500			1,098,500			1,524,000
Depletion		(57,700	)		(531,500	)		(589,200	)
Accretion of asset retirement obligations		(10,900	)		(28,200	)		(39,100	)
General and administrative		(9,800	)		(25,300	)		(35,100	)
Net income		347,100			513,500			860,600
Distributions to partners		(141,000	)		(468,900	)		(609,900	)
Balance at March 31, 2017	$	2,407,500		$	28,779,600		$	31,187,100

	Three Months Ended March 31,
	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	860,600		$	(276,100	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depletion		589,200			725,000
Non-cash loss on derivative value		-			97,700
Accretion of asset retirement obligations		39,100			37,300
Changes in operating assets and liabilities:
Increase in accounts receivable trade-affiliate		(617,400	)		(121,400	)
Increase in asset retirement receivable-affiliate		(19,600	)		(20,000	)
(Decrease) increase in accrued liabilities		(6,000	)		10,000
Net cash provided by operating activities		845,900			452,500
Cash flows from investing activities:
Net cash provided by investing activities		-			-
Cash flows from financing activities:
Distributions to partners		(609,900	)		(623,400	)
Net cash used in financing activities		(609,900	)		(623,400	)
Net change in cash		236,000			(170,900	)
Cash at beginning of period		254,600			170,900
Cash at end of period	$	490,600		$	-

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 and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Titan Energy, LLC (“Titan”). 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 has drilled and currently operates wells located in Pennsylvania, Tennessee and 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 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 continued 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 would 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 continued 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 in an attempt to ameliorate some of its liquidity concerns. 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. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility.

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.

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. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility.

On May 4, 2017, Titan entered into a definitive 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. Titan will retain its Utica Shale position, Indiana assets and West Virginia coalbed methane assets in the region. The transaction is subject to customary closing conditions, has an effective date of April 1, 2017 and is expected to close in June 2017. The net proceeds will be used to repay a portion of outstanding borrowings under Titan’s first lien credit facility. The transaction will significantly improve Titan’s first lien credit facility metrics and is expected to fulfill its borrowing base step down to $360 million, which is scheduled to occur on August 31, 2017.

The assets Titan has agreed to sell to Diversified include its indirect interests in the Partnership’s Appalachia and Marcellus assets. Titan expects that the MGP will effectuate one or more transactions involving the Partnership in connection with the sale, pursuant to which the Partnership’s Appalachia and Marcellus assets will be segregated to allow Titan to transfer the MGP’s equity interests in the Partnership with respect to the Partnership’s Appalachia and Marcellus assets. Following Titan’s transfer, Diversified will be the managing general partner and operator with respect to the Appalachia and Marcellus assets.

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.

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 months ended March 31, 2017, the Partnership did not have any derivative activity as all derivative contracts have matured. During the three months ended March 31, 2016, the Partnership recorded $200 as a gain reclassified from accumulated other comprehensive income into natural gas and oil revenues and $174,600 as a gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives.

	March 31, 2017			December 31, 2016
	March 31, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	2,719,800		$	2,719,800
Wells and related equipment		239,578,600			239,578,600
Total natural gas and oil properties		242,298,400			242,298,400
Accumulated depletion and impairment		(210,213,000	)		(209,623,800	)
Gas and oil properties, net	$	32,085,400		$	32,674,600

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

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 $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, and for all other wells a fee of $392 is charged per well per month 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 March 31,
	2017		2016
Administrative fees	$	15,100	$	15,900
Supervision fees		207,000		221,800
Transportation fees		277,000		176,100
Direct costs		222,400		472,900
Total	$	721,500	$	886,700

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.

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 March 31, 2017, the MGP withheld $236,500 of net production revenue for future plugging and abandonment costs.

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.

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.

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 have drilled and currently operate wells located in Pennsylvania, Tennessee, and 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.

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 in an attempt to ameliorate some of its liquidity concerns. The amendment provided for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the 180-day standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility.

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:

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 March 31, 2017, our MGP withheld $236,500 of net production revenues for this purpose.

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.

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 March 31,
	2017			2016
Production revenues (in thousands):
Gas	$	2,210		$	1,198

Production volumes:
Gas (mcf/day)⁽¹⁾		8,323			10,480

Average sales prices: ⁽²⁾
Gas (per mcf) ^{(1) (3)}	$	2.95		$	1.34

Production costs:
As a percent of revenues		31	%		71	%
Per mcfe⁽¹⁾	$	0.92		$	0.89

Depletion per mcfe	$	0.79		$	0.76

Natural Gas Revenues. Our natural gas revenues were $2,210,400 and $1,198,300 for the three months ended March 31, 2017 and 2016, respectively, an increase of $1,012,100 (84%). The $1,012,100 increase in natural gas revenues for the three months ended March 31, 2017 as compared to the prior year similar period was attributable to a $1,269,300 increase in our natural gas sales prices which were driven by market conditions partially offset by a $257,200 decrease in production volumes. Our production volumes decreased to 8,323 mcf per day for the three months ended March 31, 2017 from 10,480 mcf per day for the three months ended March 31, 2016, a decrease of 2,157 mcf per day (21%). The overall decrease in natural gas production volumes for the three months ended March 31, 2017 as compared to the prior year similar period resulted primarily from the normal decline 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 $174,600 for the three months ended March 31, 2016. This gain was due to mark-to-market gains primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $686,400 and $847,100 for the three months ended March 31, 2017 and 2016, respectively, a decrease of $160,700 (19%). The decrease 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 27% and 61% for the three months ended March 31, 2017 and 2016, respectively. This change was primarily attributable to changes in revenues, gas reserve quantities, and to a lesser extent, revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses for the three months ended March 31, 2017 and 2016 were $35,100 and $39,600, respectively, a decrease of $4,500 (11%). 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 operating activities consists of $845,900 net cash provided by 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 investing activities for the three months ended March 31, 2017 and 2016.

Cash used in financing activities decreased $13,500 during the three months ended March 31, 2017 to $609,900 from $623,400 for the three months ended March 31, 2016. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through March 31, 2017, our MGP withheld $236,500 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.

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.

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 March 31, 2017, our disclosure controls and procedures were effective at the reasonable assurance level.

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.

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.

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.

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)

Large accelerated filer ☐		Accelerated filer ☐		Non-accelerated filer ☐		Smaller reporting company ☒
						Emerging growth company ☐

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:
	Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	3
	Condensed Statements of Operations for the Three Months ended March 31, 2017 and 2016	4
	Condensed Statements of Comprehensive Income (Loss) for the Three Months ended March 31, 2017 and 2016	5
	Condensed Statement of Changes in Partners’ Capital for the Three Months ended March 31, 2017	6
	Condensed Statements of Cash Flows for the Three Months ended March 31, 2017 and 2016	7
	Notes to Condensed Financial Statements	8
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 4:	Controls and Procedures	16
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	16
Item 6:	Exhibits	17
SIGNATURES		18
CERTIFICATIONS

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

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

	By:	Atlas Resources, LLC, its
		Managing General Partner

Date: May 15, 2017	By:	/s/ FREDRICK M. STOLERU
		Fredrick M. Stoleru, Chairman of the Board and Chief Executive Officer (principal executive officer)