10-Q

United States

Securities and Exchange Commission

Washington, D.C. 20549

_________________________________________________________________________ 

Form 10-Q

_________________________________________________________________________ 

(Mark One)

X 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 000-55840

_________________________________________________________________________ 

DGOC SERIES 18(C), L.P.

(Name of small business issuer in its charter)

_________________________________________________________________________ 

Delaware	82-2114425
(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  X    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  X    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  X
			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  X

1

DGOC SERIES 18(C), L.P.

INDEX TO QUARTERLY REPORT

ON FORM 10-Q

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)
Item 1:	Financial Statements (Unaudited)
	Condensed Balance Sheets	3
	Condensed Statements of Operations	4
	Condensed Statements of Comprehensive Income (Loss)	5
	Condensed Statement of Changes in Partners’ Capital	6
	Condensed Statements of Cash Flows	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	15
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings	16
Item 6:	Exhibits	17
SIGNATURES		18
CERTIFICATIONS

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DGOC SERIES 18(C), L.P.

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash	$	324,500	$	249,000
Accounts receivable trade–affiliate	1,164,700		1,139,500
Total current assets	1,489,200		1,388,500
Natural gas properties, net	29,344,600		30,904,400
Long-term asset retirement receivable-affiliate	270,500		170,700
Total assets	$	31,104,300	$	32,463,600
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	27,500	$	39,700
Total current liabilities	27,500		39,700
Asset retirement obligations	2,740,400		2,641,800
Commitments and contingencies (Note 4)
Partners’ capital:
Managing general partner’s interest	2,538,800		2,613,200
Limited partners’ interest (22,928.90 units)	25,797,600		27,168,900
Total partners’ capital	28,336,400		29,782,100
Total liabilities and partners’ capital	$	31,104,300	$	32,463,600

See accompanying notes to condensed financial statements.

3

DGOC SERIES 18(C), L.P.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
REVENUES
Natural gas	$	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)	$	318,900	$	(1,100	)	$	1,842,600	$	(435,100	)
Allocation of net income (loss):
Managing general partner	$	185,400	$	123,500		$	816,100	$	278,100
Limited partners	$	133,500	$	(124,600	)	$	1,026,500	$	(713,200	)
Net income (loss) per limited partnership unit	$	6	$	(5	)	$	45	$	(31	)

See accompanying notes to condensed financial statements.

4

DGOC SERIES 18(C), L.P.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Net income (loss)	$	318,900	$	(1,100	)	$	1,842,600		$	(435,100	)
Other comprehensive loss:
Difference in estimated hedge receivable	—		63,100			67,400			181,400
Reclassification adjustment to net income (loss) of mark-to-market gains on cash flow hedges	—		(63,200		)	(67,400		)	(181,900		)
Total other comprehensive loss	—		(100		)	—			(500		)
Comprehensive income (loss)	$	318,900	$	(1,200	)	$	1,842,600		$	(435,600	)

See accompanying notes to condensed financial statements.

5

DGOC SERIES 18(C), L.P.

CONDENSED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

	Managing General Partner			Limited Partners			Total
Balance at December 31, 2016	$	2,613,200		$	27,168,900		$	29,782,100
Participation in revenues, costs and expenses:
Net production revenues	1,005,700			2,591,300			3,597,000
Depletion	(135,200		)	(1,424,600		)	(1,559,800		)
Accretion of asset retirement obligations	(27,600		)	(71,000		)	(98,600		)
General and administrative	(26,800		)	(69,200		)	(96,000		)
Net income	816,100			1,026,500			1,842,600
Distributions to partners	(890,500		)	(2,397,800		)	(3,288,300		)
Balance at September 30, 2017	$	2,538,800		$	25,797,600		$	28,336,400

See accompanying notes to condensed financial statements.

6

DGOC SERIES 18(C), L.P.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	1,842,600		$	(435,100	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion	1,559,800			1,923,200
Non-cash loss on derivative value	—			648,700
Accretion of asset retirement obligations	98,600			93,700
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate	(25,200		)	117,800
Increase in asset retirement receivable-affiliate	(99,800		)	(48,000		)
(Decrease) increase in accrued liabilities	(12,200		)	15,300
Net cash provided by operating activities	3,363,800			2,315,600
Cash flows from investing activities:
Net cash provided by investing activities	—			—
Cash flows from financing activities:
Distributions to partners	(3,288,300		)	(2,228,200		)
Net cash used in financing activities	(3,288,300		)	(2,228,200		)
Net change in cash	75,500			87,400
Cash at beginning of period	249,000			170,900
Cash at end of period	$	324,500		$	258,300

See accompanying notes to condensed financial statements.

7

DGOC SERIES 18(C), L.P.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - DESCRIPTION OF BUSINESS

DGOC Series 18(C), L.P. (the "Partnership") is a Delaware limited partnership, formed on July 6, 2017 and includes the Appalachian-based assets that were previously included within, Atlas Resources Public 18-2009(C), L.P. ("Predecessor Partnership") that was formed on June 9, 2009 and was then managed by Atlas Resources, LLC ("Atlas" or "Previous MGP"). DGOC Partnership Holdings, LLC now serves as the Partnership's Managing General Partner (“DGOC Holdings” or the “MGP”) and certain affiliates of the MGP serve as our Operator ("Operator"). DGOC Holdings is an indirect subsidiary of Diversified Gas & Oil, PLC (“Diversified”; AIM: DGOC). Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to DGOC Series 18(C), L.P.

Atlas previously served as the Partnership's Managing General Partner and Operator . Atlas is an indirect subsidiary of Titan Energy, LLC (“Titan”). On May 4, 2017, Titan entered into a definitive agreement to sell, among other conventional assets, its general and limited partnership equity interest (“Equity Interest”) in the Partnership to Diversified (the “Purchase and Sale Agreement” or “PSA”). The transaction was subject to customary closing conditions, had an effective date of April 1, 2017 and closed on September 29, 2017. Prior to closing the PSA, the Previous MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania and Tennessee on June 30, 2017. Upon closing the PSA, the Previous MGP’s Equity Interest in the Partnership was transferred to DGOC Holdings and DGOC Holdings was admitted as a substitute managing general partner of the Partnership and continues to serve as Operator.

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. We have no employees and rely on our MGP to staff and manage our operations, which in turn, relies on Atlas Energy Group, LLC, Titan’s parent company, for administrative services through a Transition Services Agreement ("TSA") effective through December 31, 2017. After the expiration of the TSA, staffing will be provided by an affiliate of Diversified.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas. Produced natural gas is then delivered to market through third-party gas gathering systems. The Partnership intends to produce its wells until they are sold, depleted or become uneconomical to produce, at which time they will be plugged and abandoned. 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 will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may, in addition to decreasing the Partnership’s revenues, also reduce the amount of natural gas that the Partnership can produce economically.

Liquidity and Capital Resources

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. Prices for natural gas began to decline significantly during the fourth quarter of 2014 and continue to remain low, on a relative basis, in 2017. These lower commodity prices negatively impact the Partnership’s revenues, earnings and cash flows. In addition, low commodity prices place downward pressure on the Partnership’s proved natural gas reserves as some volumes in the later years of the life of the well become uneconomic to produce at the lower prices. The MGP is continuing the efforts of the Previous MGP 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, and deferring and/or 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.

8

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These condensed financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results to be expected for the full year. These condensed financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the financial statements for the year ended December 31, 2016 and notes thereto included in our Form 10-12G Registration Statement, which include a summary of the significant accounting policies.

Use of Estimates

The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires the MGP 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 Previous 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 then 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 condensed 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 had no any derivative activity since all derivative contracts settled.  During the three and nine months ended September 30, 2016, the Partnership recorded $100 and $500, respectively, as a loss reclassified from accumulated other comprehensive income into natural gas revenues and $9,200 and $14,200 as a gain, respectively, subsequent to hedge accounting recognized in gain on mark-to-market derivatives.

9

Natural Gas Properties

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

	September 30, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	1,660,400		$	1,660,400
Wells and related equipment	210,127,800			210,127,800
Total natural gas properties	211,788,200			211,788,200
Accumulated depletion and impairment	(182,443,600		)	(180,883,800		)
Natural gas properties, net	$	29,344,600		$	30,904,400

We review our natural gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. The review of the Partnership’s natural gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. There was no triggering event in the third quarter of 2017 that would cause us to believe the value of natural gas producing properties should be impaired.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.

The MGP has made significant progress in its assessment of the adoption of this standard on its revenue-related contracts. The Partnership currently recognizes revenue under the sales method of accounting, and to date, has not identified any contracts that would require a change from the sales method. To date, the MGP has not identified any material impact that the new standard will have on the Partnership's Financial Statements with the exception of new disclosures. The Partnership intends to adopt the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

10

NOTE 3 - 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 $975 per well per month for Marcellus 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Administrative fees	$	13,500	$	14,200	$	41,200	$	42,600
Supervision fees	175,400		184,900		535,600		554,300
Transportation fees	184,500		172,500		708,300		523,000
Direct costs	128,800		122,800		390,500		534,900
Total	$	502,200	$	494,400	$	1,675,600	$	1,654,800

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 4 - 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 Operator has withheld $270,500 of net production revenue for future plugging and abandonment costs.  

Environmental risk is inherent to natural gas operations, and we and our affiliates may be, at times, subject to potential environmental remediation liability. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our natural gas operations.

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 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.

11

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 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.

The Partnership cautions you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond its control, incident to the production and sale of natural gas. These risks include, but are not limited to, the risks described in our Registration Statement on Form 10-12G filed September 9, 2017 for the year ended December 31, 2016, including under the heading entitled “Forward-Looking Statements,” and all quarterly reports on Form 10-Q filed subsequently thereto. Should one or more of the risks or uncertainties described herein or in our Registration Statement on Form 10-12G occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

General

See Note 1 to our condensed financial statements for a description of our business and information regarding the creation of the business upon the sale of certain Appalachian-based assets from the previous managing general partner ("Previous MGP") to the current managing general partner ("MGP").

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. Our produced natural gas 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 production. Our results of operations are dependent upon the difference between prices received for our natural gas production and the costs to find and produce such natural gas. Natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control.

Beginning in the third quarter of 2014, the global prices for natural gas began a dramatic decline which continued through 2015 and into 2016. Current prices, while higher than those in early 2016, are significantly less than they were in the several years prior to mid-2014. A decline in natural gas prices and a sustained period of natural gas prices at depressed levels could have a material adverse effect on our financial condition. We currently do not have any derivative contracts to hedge against declines in commodity prices.

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 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, the Previous MGP withheld $270,500 of net production revenues for this purpose.  

12

Results of Operations

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	$	1,355		$	1,123		$	5,177		$	3,222
Production volumes:
Gas (mcf/day) (1)	6,996			8,390			7,337			8,857
Change vs prior	(17		)%				(17		)%
Average sales prices: (2)
Gas (per mcf) (1) (3)	$	2.11		$	1.56		$	2.58		$	1.43
Change vs prior	35.26		%				80.42		%
Production costs:
As a percent of revenues	35		%	41		%	31		%	48		%
Per mcfe (1)	$	0.73		$	0.60		$	0.79		$	0.64
Depletion per mcfe	$	0.78		$	0.80		$	0.78		$	0.80

___________________________________

(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.

(2) Average sales prices represent accrual basis pricing.

(3) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by total volume for the period. Previously recognized gains were $83,800 and $244,200 for the three and nine months ended September 30, 2016, respectively.

Revenues

The following tables reconcile the changes in natural gas and total revenue 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	$	1,122,800
Volume decrease	(176,200		)
Price increase	408,300
Net increase	232,100
Revenues for the three months ended September 30, 2017	$	1,354,900

	Nine Months Ended September 30,
	Natural gas
Revenues for the nine months ended September 30, 2016	$	3,222,400
Volume decrease	(553,100		)
Price increase	2,507,300
Net increase	1,954,200
Revenues for the nine months ended September 30, 2017	$	5,176,600

13

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.

Costs and expenses

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
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

Costs and Expenses. Production expenses were $471,000 and $459,400 for the three months ended September 30, 2017 and 2016, respectively, an increase of $11,600 (3%) and $1,579,600 and $1,548,500 for the nine months ended September 30, 2017 and 2016, respectively, an increase of $31,100 (2%).  The increase for the three months ended September 30, 2017 when compared to the prior year similar period was mainly a result of a increase in transportation fees. The increasefor the nine months ended September 30, 2017 when compared to the prior year similar periodwas mostly attributable to an increase in transportation fees due to an increase in production revenue.

Depletion expense, which is calculated by taking the total capital invested to develop the producing wells divided by the total estimated reserves of the well and is then recognized for each unit of production during the period. For the three and nine months periods ended September 30, 2017 and 2016 produced volumes were down 17% which correlates to the drop in depletion expense.

General and administrative expenses for the three months ended September 30, 2017 and 2016 were $31,200 and $35,000, respectively, a decrease of $3,800 (11%). For the nine months ended September 30, 2017 and 2016, these expenses were $96,000 and $106,300, respectively, a decrease of $10,300 (10%). 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 were $3,363,800 and $2,315,600 for the nine months ended September 30, 2017 and 2016, respectively, and include cash receipts and disbursements attributable to our normal monthly operating cycle for gas production, lease operating expenses, gathering, processing and transportation expenses, severance taxes, general and administrative expenses. The increase in cash flows resulted primarily from increased revenues driven by higher realized natural gas prices.

No cash provided by investing activities for the nine months ended September 30, 2017 and 2016.

Cash used in financing activities increased $1,060,100 during the nine months ended September 30, 2017 to $3,288,300 from $2,228,200 for the nine months ended September 30, 2016. This increase was due to an increase in cash distributions to partners, which was primarily driven by a 61% increase in revenues.

Liquidity and Capital Resources

See Note 1 to our condensed financial statements for additional information related to liquidity and capital resources.

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 Registration of Securities on Form 10-12G filed September 9, 2017.

14

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The MGP maintains 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, the MGP's Chief Executive Officer and Principal Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, the MGP 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 the MGP's Chief Executive Officer and Principal Financial Officer and, the MGP has carried out an evaluation of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the MGP's Chief Executive Officer and Principal Financial Officer concluded that, as of September 30, 2017, our its disclosure controls and procedures were effective.

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.

15

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. The MGP 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.

The MGP's affiliates and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP 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.

16

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description
3.1		Certificate of Limited Partnership for DGOC Series 18(C), L.P. (incorporated by reference to Exhibit 3.1 to the Company's Form 10-12G Registration Statement filed on September 8, 2017)
3.2		Certificate and Agreement of Limited Partnership for DGOC Series 18(C), L.P. (incorporated by reference to Exhibit 3.2 to the Company's Form 10-12G Registration Statement filed on September 8, 2017)
31.1	(a)	Certification Pursuant to Rule 13a-14/15(d)-14
31.2	(a)	Certification Pursuant to Rule 13a-14/15(d)-14
32.1	(b)	Section 1350 Certification
32.2	(b)	Section 1350 Certification
101	(c)	Interactive Data File
(a)	Filed herewith
(b)	Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as "accompanying" this report and not "filed" as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(c)	Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

_____________________________________

17

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.

	DGOC SERIES 18(C), L.P.
	By:	DGOC Partnership Holdings, LLC, its
		Managing General Partner
Date: November 14, 2017	By:	/s/ ROBERT R. HUTSON, JR.
		Robert R. Hutson, Jr., Chief Executive Officer (principal executive officer) of the Managing General Partner

Date: November 14, 2017	By:	/s/ BRADLEY G. GRAY
		Bradley G. Gray, Chief Operating Officer (principal financial officer)of the Managing General Partner

18

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert R. Hutson, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2017 of DGOC Series 18(C), L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ ROBERT R. HUTSON, JR.
Name:	Robert R. Hutson, Jr.,
Title:	Chief Executive Officer (principal executive officer) of the Managing General Partner
Date:	November 14, 2017

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Bradley G. Gray, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 2017 of DGOC Series 18(C), L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have;

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within the entity, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ BRADLEY G. GRAY
Name:	Bradley G. Gray,
Title:	Chief Operating Officer (principal financial officer) of the Managing General Partner
Date:	November 14, 2017

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of DGOC Series 18(C), L.P. (the “Partnership”) on Form 10-Q for the period ended September 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert R. Hutson, Chief Executive Officer (principal executive officer) of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ ROBERT R. HUTSON, JR.
Name:	Robert R. Hutson, Jr.
Title:	Chief Executive Officer (principal executive officer) of the Managing General Partner
Date:	November 14, 2017

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of DGOC Series 18(C), L.P. (the “Partnership”) on Form 10-Q for the period ended September 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bradley G. Gray, Chief Operating Officer (principal financial officer) of the Managing General Partner, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ BRADLEY G. GRAY
Name:	Bradley G. Gray,
Title:	Chief Operating Officer (principal financial officer ) of the Managing General Partner
Date:	November 14, 2017

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2017 shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Entity Registrant Name	DGOC Series 18C LP
Entity Central Index Key	0001711736
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

XML

CONDENSED BALANCE SHEETS - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash	$ 324,500	$ 249,000
Accounts receivable trade–affiliate	1,164,700	1,139,500
Total current assets	1,489,200	1,388,500
Natural gas properties, net	29,344,600	30,904,400
Long-term asset retirement receivable-affiliate	270,500	170,700
Total assets	31,104,300	32,463,600
Current liabilities:
Accrued liabilities	27,500	39,700
Total current liabilities	27,500	39,700
Asset retirement obligations	2,740,400	2,641,800
Commitments and contingencies (Note 4)
Partners’ capital:
Managing general partner’s interest	2,538,800	2,613,200
Limited partners’ interest (22,928.90 units)	25,797,600	27,168,900
Total partners’ capital	28,336,400	29,782,100
Total liabilities and partners’ capital	$ 31,104,300	$ 32,463,600

XML

CONDENSED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Limited partners' units	22,928.90	22,928.90

XML

CONDENSED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES
Natural gas	$ 1,354,900	$ 1,122,800	$ 5,176,600	$ 3,222,400
Gain on mark-to-market derivatives	0	9,200	0	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)	318,900	(1,100)	1,842,600	(435,100)
Allocation of net income (loss):
Managing general partner	185,400	123,500	816,100	278,100
Limited partners	$ 133,500	$ (124,600)	$ 1,026,500	$ (713,200)
Net income (loss) per limited partnership unit (in dollars per share)	$ 6	$ (5)	$ 45	$ (31)

XML

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 318,900	$ (1,100)	$ 1,842,600	$ (435,100)
Other comprehensive loss:
Difference in estimated hedge receivable	0	63,100	67,400	181,400
Reclassification adjustment to net income (loss) of mark-to-market gains on cash flow hedges	0	(63,200)	(67,400)	(181,900)
Total other comprehensive loss	0	(100)	0	(500)
Comprehensive income (loss)	$ 318,900	$ (1,200)	$ 1,842,600	$ (435,600)

XML

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL - 9 months ended Sep. 30, 2017 - USD ($)	Total	Managing General Partner	Limited Partners
Beginning balance at Dec. 31, 2016	$ 29,782,100	$ 2,613,200	$ 27,168,900
Participation in revenues, costs and expenses:
Net production revenues	3,597,000	1,005,700	2,591,300
Depletion	(1,559,800)	(135,200)	(1,424,600)
Accretion of asset retirement obligations	(98,600)	(27,600)	(71,000)
General and administrative	(96,000)	(26,800)	(69,200)
Net income (loss)	1,842,600	816,100	1,026,500
Distributions to partners	(3,288,300)	(890,500)	(2,397,800)
Ending balance at Sep. 30, 2017	$ 28,336,400	$ 2,538,800	$ 25,797,600

XML

CONDENSED STATEMENTS OF CASH FLOWS - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ 1,842,600	$ (435,100)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion	1,559,800	1,923,200
Non-cash loss on derivative value	0	648,700
Accretion of asset retirement obligations	98,600	93,700
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate	(25,200)	117,800
Increase in asset retirement receivable-affiliate	(99,800)	(48,000)
(Decrease) increase in accrued liabilities	(12,200)	15,300
Net cash provided by operating activities	3,363,800	2,315,600
Cash flows from investing activities:
Net cash provided by investing activities	0	0
Cash flows from financing activities:
Distributions to partners	(3,288,300)	(2,228,200)
Net cash used in financing activities	(3,288,300)	(2,228,200)
Net change in cash	75,500	87,400
Cash at beginning of period	249,000	170,900
Cash at end of period	$ 324,500	$ 258,300

XML

Description of Business

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

DESCRIPTION OF BUSINESS

DESCRIPTION OF BUSINESS

DGOC Series 18(C), L.P. (the "Partnership") is a Delaware limited partnership, formed on July 6, 2017 and includes the Appalachian-based assets that were previously included within, Atlas Resources Public 18-2009(C), L.P. ("Predecessor Partnership") that was formed on June 9, 2009 and was then managed by Atlas Resources, LLC ("Atlas" or "Previous MGP"). DGOC Partnership Holdings, LLC now serves as the Partnership's Managing General Partner (“DGOC Holdings” or the “MGP”) and certain affiliates of the MGP serve as our Operator ("Operator"). DGOC Holdings is an indirect subsidiary of Diversified Gas & Oil, PLC (“Diversified”; AIM: DGOC). Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to DGOC Series 18(C), L.P.

Atlas previously served as the Partnership's Managing General Partner and Operator . Atlas is an indirect subsidiary of Titan Energy, LLC (“Titan”). On May 4, 2017, Titan entered into a definitive agreement to sell, among other conventional assets, its general and limited partnership equity interest (“Equity Interest”) in the Partnership to Diversified (the “Purchase and Sale Agreement” or “PSA”). The transaction was subject to customary closing conditions, had an effective date of April 1, 2017 and closed on September 29, 2017. Prior to closing the PSA, the Previous MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania and Tennessee on June 30, 2017. Upon closing the PSA, the Previous MGP’s Equity Interest in the Partnership was transferred to DGOC Holdings and DGOC Holdings was admitted as a substitute managing general partner of the Partnership and continues to serve as Operator.

The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. We have no employees and rely on our MGP to staff and manage our operations, which in turn, relies on Atlas Energy Group, LLC, Titan’s parent company, for administrative services through a Transition Services Agreement ("TSA") effective through December 31, 2017. After the expiration of the TSA, staffing will be provided by an affiliate of Diversified.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas. Produced natural gas is then delivered to market through third-party gas gathering systems. The Partnership intends to produce its wells until they are sold, depleted or become uneconomical to produce, at which time they will be plugged and abandoned. 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 will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas prices may, in addition to decreasing the Partnership’s revenues, also reduce the amount of natural gas that the Partnership can produce economically.

Liquidity and Capital Resources

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. Prices for natural gas began to decline significantly during the fourth quarter of 2014 and continue to remain low, on a relative basis, in 2017. These lower commodity prices negatively impact the Partnership’s revenues, earnings and cash flows. In addition, low commodity prices place downward pressure on the Partnership’s proved natural gas reserves as some volumes in the later years of the life of the well become uneconomic to produce at the lower prices. The MGP is continuing the efforts of the Previous MGP 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, and deferring and/or 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.

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These condensed financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results to be expected for the full year. These condensed financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the financial statements for the year ended December 31, 2016 and notes thereto included in our Form 10-12G Registration Statement, which include a summary of the significant accounting policies.

Use of Estimates

The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires the MGP 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 Previous 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 then 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 condensed 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 had no any derivative activity since all derivative contracts settled.  During the three and nine months ended September 30, 2016, the Partnership recorded $100 and $500, respectively, as a loss reclassified from accumulated other comprehensive income into natural gas revenues and $9,200 and $14,200 as a gain, respectively, subsequent to hedge accounting recognized in gain on mark-to-market derivatives.

Natural Gas Properties

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

	September 30, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	1,660,400		$	1,660,400
Wells and related equipment	210,127,800			210,127,800
Total natural gas properties	211,788,200			211,788,200
Accumulated depletion and impairment	(182,443,600		)	(180,883,800		)
Natural gas properties, net	$	29,344,600		$	30,904,400

We review our natural gas producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. The review of the Partnership’s natural gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. There was no triggering event in the third quarter of 2017 that would cause us to believe the value of natural gas producing properties should be impaired.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.

The MGP has made significant progress in its assessment of the adoption of this standard on its revenue-related contracts. The Partnership currently recognizes revenue under the sales method of accounting, and to date, has not identified any contracts that would require a change from the sales method. To date, the MGP has not identified any material impact that the new standard will have on the Partnership's Financial Statements with the exception of new disclosures. The Partnership intends to adopt the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

XML

Certain Relationships and Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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 $975 per well per month for Marcellus 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Administrative fees	$	13,500	$	14,200	$	41,200	$	42,600
Supervision fees	175,400		184,900		535,600		554,300
Transportation fees	184,500		172,500		708,300		523,000
Direct costs	128,800		122,800		390,500		534,900
Total	$	502,200	$	494,400	$	1,675,600	$	1,654,800

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.    

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

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 Operator has withheld $270,500 of net production revenue for future plugging and abandonment costs.  

Environmental risk is inherent to natural gas operations, and we and our affiliates may be, at times, subject to potential environmental remediation liability. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our natural gas operations.

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 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.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Summary Of Significant Accounting Policies [Line Items]

Use of Estimates

Use of Estimates

The preparation of the Partnership’s condensed financial statements in conformity with U.S. GAAP requires the MGP 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

Derivative Instruments

The Partnership’s Previous 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 then 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 condensed 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 had no any derivative activity since all derivative contracts settled.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Summary of Gas Properties

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

	September 30, 2017			December 31, 2016
Proved properties:
Leasehold interests	$	1,660,400		$	1,660,400
Wells and related equipment	210,127,800			210,127,800
Total natural gas properties	211,788,200			211,788,200
Accumulated depletion and impairment	(182,443,600		)	(180,883,800		)
Natural gas properties, net	$	29,344,600		$	30,904,400

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Certain Relationships and Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Certain Relationships and Related Party Transactions

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	$	13,500	$	14,200	$	41,200	$	42,600
Supervision fees	175,400		184,900		535,600		554,300
Transportation fees	184,500		172,500		708,300		523,000
Direct costs	128,800		122,800		390,500		534,900
Total	$	502,200	$	494,400	$	1,675,600	$	1,654,800

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Summary of Significant Accounting Policies (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Loss reclassified from accumulated other comprehensive income into natural gas revenues		$ 100		$ 500
Gain subsequent to hedge accounting recognized in (loss) gain on mark-to-market derivatives	$ 0	$ 9,200	$ 0	$ 14,200

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Summary of Significant Accounting Policies - Summary of Gas and Oil Properties (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Total natural gas and oil properties	$ 211,788,200	$ 211,788,200
Accumulated depletion and impairment	(182,443,600)	(180,883,800)
Gas and oil properties, net	29,344,600	30,904,400
Leasehold interests
Property, Plant and Equipment [Line Items]
Total natural gas and oil properties	1,660,400	1,660,400
Wells and related equipment
Property, Plant and Equipment [Line Items]
Total natural gas and oil properties	$ 210,127,800	$ 210,127,800

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Certain Relationships and Related Party Transactions (Details) - MGP and Affiliates	9 Months Ended
	Sep. 30, 2017 $ / mo
General and administrative expenses
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Production
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	16.00%
Production | Marcellus wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	975
Production | Other Wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	392

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Certain Relationships and Related Party Transactions - Costs and the Periods Incurred (Details) - MGP and Affiliates - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Related Party Transaction [Line Items]
Related party transaction, expenses from transactions with related party	$ 502,200	$ 494,400	$ 1,675,600	$ 1,654,800
Administrative fees
Related Party Transaction [Line Items]
Related party transaction, expenses from transactions with related party	13,500	14,200	41,200	42,600
Supervision fees
Related Party Transaction [Line Items]
Related party transaction, expenses from transactions with related party	175,400	184,900	535,600	554,300
Transportation fees
Related Party Transaction [Line Items]
Related party transaction, expenses from transactions with related party	184,500	172,500	708,300	523,000
Direct costs
Related Party Transaction [Line Items]
Related party transaction, expenses from transactions with related party	$ 128,800	$ 122,800	$ 390,500	$ 534,900

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Commitments and Contingencies (Details)	9 Months Ended
	Sep. 30, 2017 USD ($) $ / mo
Commitments and Contingencies Disclosure [Abstract]
Investor partners ownership interest presented for purchase by the MGP, maximum percentage	5.00%
Operator fee per well to cover estimated future plugging and abandonment costs, monthly | $ / mo	200
Net production revenue for future plugging and abandonment costs | $	$ 270,500