DGOC Series 18C 10-Q 14 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2017shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Entity Registrant Name	DGOC Series 18C LP
Entity Central Index Key	1,711,736
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED BALANCE SHEETS

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

CONDENSED BALANCE SHEETS (Paren

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

CONDENSED STATEMENTS OF OPERATI

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)

CONDENSED STATEMENTS OF COMPREH

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)

CONDENSED STATEMENT OF CHANGES

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

CONDENSED STATEMENTS OF CASH FL

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

Description of Business

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.

Summary of Significant Accounti

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, December 31, 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.

Certain Relationships and Relat

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 Nine Months Ended 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.

Commitments and Contingencies

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.

Summary of Significant Accoun12

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

Summary of Significant Accoun13

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, December 31, 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

Certain Relationships and Rel14

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 Nine Months Ended 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

Summary of Significant Accoun15

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

Summary of Significant Accoun16

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

Certain Relationships and Rel17

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

Certain Relationships and Rel18

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

Commitments and Contingencies (

Commitments and Contingencies (Details)	9 Months Ended
	Sep. 30, 2017USD ($)$ / 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