Exhibit 99.1

 

 

 

Report of Independent Auditors

 

The Board of Managers and Members
Alta Resources Development, LLC

 

Report on the Financial Statements

 

We have audited the accompanying consolidated financial statements of Alta Resources Development, LLC and its subsidiaries, which comprise the consolidated balance sheets as of June 30, 2020 and 2019, and the related consolidated statements of income, changes in members’ equity, and cash flows for each of the three years in the period ended June 30, 2020, and the related notes to the consolidated financial statements (collectively, the “financial statements”).

 

Management’s Responsibility for the Financial Statements

 

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

 

Auditor’s Responsibility

 

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

 

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

 

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

 

Opinion

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alta Resources Development, LLC and its subsidiaries as of June 30, 2020 and 2019, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2020 in accordance with accounting principles generally accepted in the United States of America.

 

/s/ Moss Adams LLP

 

Houston, Texas
September 28, 2020

 

  

Alta Resources Development, LLC

Consolidated Balance Sheets

  

		June 30,
		2020				2019
		(Amounts in thousands)
ASSETS						​
CURRENT ASSETS:		​				​
Cash and cash equivalents		$	11,986			$	27,103
Accounts receivable:			​				​
Natural gas sales receivables			35,672				47,041
Joint interest billings and other			3,394				4,803
Advance to affiliates			609				—
Assets from risk management activities			37,544				30,783
Prepaid expenses and other current assets			1,952				1,744
Total current assets			91,157				111,474
PROPERTY AND EQUIPMENT:			​				​
Natural gas properties – full cost method:			​				​
Evaluated properties			2,074,787				1,784,303
Unevaluated properties			8,146				7,055
Less: accumulated depreciation, depletion and amortization			(661,327	)			(351,344	)
Net natural gas properties			1,421,606				1,440,014
Other property and equipment – net of accumulated depreciation of $2,166 and $1,525 as of June 30, 2020 and 2019, respectively			1,231				1,357
Net property and equipment			1,422,837				1,441,371
NON-CURRENT ASSETS:			​				​
Assets from risk management activities			290				6,140
Note receivable from affiliates and other			2,439				—
Total non-current assets			2,729				6,140
TOTAL ASSETS		$	1,516,723			$	1,558,985

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

Alta Resources Development, LLC

Consolidated Balance Sheets

 

		June 30,
		2020				2019
		(Amounts in thousands)
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	22,822			$	18,319
Accrued capital expenditures			49,193				27,833
Accrued liabilities			13,969				13,887
Revenue-related payables			29,775				38,514
Liabilities from risk management activities			7,811				16,942
Total current liabilities			123,570				115,495
NON-CURRENT LIABILITIES:
Long-term debt, net			604,155				621,126
Asset retirement obligations			21,526				18,961
Liabilities from risk management activities			22,551				8,628
Other liabilities			2,405				2,591
Total non-current liabilities			650,637				651,306
Total liabilities			774,207				766,801
COMMITMENTS AND CONTINGENCIES (Note 5)
MEMBERS’ EQUITY:
Class A members — contributed capital, net of distributions and fees			20,919				27,011
Class B members — contributed capital, net of distributions and fees			262,376				338,784
Retained earnings			459,221				426,389
Total members’ equity			742,516				792,184
TOTAL LIABILITIES AND MEMBERS’ EQUITY		$	1,516,723			$	1,558,985

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

Alta Resources Development, LLC

Consolidated Statements of Income

  

		Years Ended June 30,
		2020				2019				2018
		(Amounts in thousands)
REVENUES:		​				​				​
Natural gas revenues		$	448,076			$	684,406			$	483,575
Other operating revenues			15,217				9,756				7,115
Net gain (loss) on commodity risk management activities			103,716				(4,822	)			13,989
Total revenues			567,009				689,340				504,679
COSTS AND EXPENSES:			​				​				​
Gathering, transportation and compression			109,670				99,141				97,183
Direct operating			55,799				53,383				45,060
Depreciation, depletion and amortization			171,562				158,192				157,831
Impairment of natural gas properties			139,063				—				—
General and administrative			8,631				10,791				16,802
Accretion of asset retirement obligations			1,618				1,433				1,242
Total costs and expenses			486,343				322,940				318,118
OTHER INCOME (EXPENSE):			​				​				​
Interest expense, net and other			(35,048	)			(52,016	)			(43,060	)
Net gain (loss) on interest rate derivatives			(12,786	)			(7,099	)			427
Total other expense			(47,834	)			(59,115	)			(42,633	)
NET INCOME		$	32,832			$	307,285			$	143,928

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

Alta Resources Development, LLC

Consolidated Statements of Changes in Members’ Equity

 

		For the Years Ended June 30, 2020, 2019, and 2018
		Class A Member				Class B Members				Total Members’ Equity
		(Amounts in thousands)
BALANCES, July 1, 2017		$	57,510			$	721,661			$	779,171
Distributions			(18,357	)			(230,243	)			(248,600	)
Net income			10,628				133,300				143,928
BALANCES, June 30, 2018			49,781				624,718				674,499
Distributions			(14,000	)			(175,600	)			(189,600	)
Net income			22,690				284,595				307,285
BALANCES, June 30, 2019			58,471				733,713				792,184
Distributions			(6,092	)			(76,408	)			(82,500	)
Net income			2,424				30,408				32,832
BALANCES, June 30, 2020		$	54,803			$	687,713			$	742,516

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

Alta Resources Development, LLC

Consolidated Statements of Cash Flows

 

		Years Ended June 30,
		2020				2019				2018
		(Amounts in Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	32,832		$		307,285			$	143,928
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization			171,562				158,192				157,831
Impairment of natural gas properties			139,063				—				—
Accretion of asset retirement obligations			1,618				1,433				1,242
Amortization of deferred financing costs			2,967				2,463				2,420
Unrealized gain on commodity risk management activities			(7,276	)			(52,373	)			(6,903	)
Unrealized loss (gain) on interest rate derivatives			11,157				7,157				(484	)
Changes in operating assets and liabilities:
Accounts receivable			12,778				(8,525	)			23,172
Note receivable from affiliates and other			(2,400	)			—				—
Prepaid expenses, advance to affiliates and other assets			(817	)			1,113				(1,381	)
Accounts payable, accrued liabilities and other liabilities			(4,337	)			20,208				45,275
Settlement of asset retirement obligations			(160	)			(802	)			—
Net cash provided by operating activities			356,987				436,151				365,100
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas properties and other property and equipment			(269,627	)			(208,196	)			(132,345	)
Acquisitions of natural gas properties			—				(25,000	)			(113,992	)
Proceeds from sale of natural gas properties			—				—				1,016
Net cash used in investing activities			(269,627	)			(233,196	)			(245,321	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt			350,214				461,000				489,000
Payments of long-term debt			(370,152	)			(465,220	)			(390,513	)
Member distributions			(82,500	)			(189,600	)			(248,600	)
Deferred financing costs and other			(39	)			(1,453	)			—
Net cash used in financing activities			(102,477	)			(195,273	)			(150,113	)
NET CHANGE IN CASH AND CASH EQUIVALENTS			(15,117	)			7,682				(30,334	)
CASH AND CASH EQUIVALENTS, beginning of year			27,103				19,421				49,755
CASH AND CASH EQUIVALENTS, end of year		$	11,986			$	27,103			$	19,421
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest		$	32,487			$	49,291			$	39,725
NON-CASH ACTIVITIES:
Accrual for capital expenditures		$	49,193			$	27,833			$	31,118
Asset retirement obligations incurred		$	1,107			$	1,396			$	147
Asset retirement obligations assumed in business acquisitions		$	—			$	—			$	1,618

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

Note 1 — Organization and Summary of Significant Accounting Policies

 

Organization and Principles of Consolidation

 

Alta Resources Development, LLC is a Delaware limited liability company formed on July 24, 2015, together with its subsidiaries (collectively, the Company) to engage in the acquisition, exploration and development of onshore oil and natural gas assets in North America. The Company’s consolidated financial statements presented herein include the accounts of ARD Operating, LLC and Alta Marcellus Development, LLC (AMD) for which the Company owns 100% of each, as well as Alta Marcellus Midstream, LLC (AMM), Alta Energy Marketing, LLC (AEM), and Alta Marcellus E&P, LLC, which was dissolved July 2, 2018, all of which are 100% owned by AMD.

 

The Company operates in one segment, natural gas and oil development, exploitation, exploration and production in North America. The Company’s corporate office is located in Houston, Texas, its field office is located in Williamsport, Pennsylvania and its operations are principally located in seven counties in Pennsylvania.

 

Basis of Presentation

 

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions.

 

Reclassifications

 

Certain 2019 and 2018 amounts have been reclassified to conform to current presentation. These reclassifications had no effect on 2019 or 2018 net income, total assets and liabilities, members’ equity, or cash flows.

 

Recently Adopted Accounting Standard

 

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Codification (ASC) 606, as subsequently amended. ASC 606 supersedes current revenue recognition requirements in ASC 605, Revenue Recognition, and industry-specific guidance. The codification requires an entity to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The Company adopted this standard as of July 1, 2019 using the modified retrospective transition method. The implementation of this standard did not result in a cumulative-effect adjustment on date of adoption and did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

 

In March 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments (Topic 230), which clarifies classification of certain cash receipts and payments on the statement of cash flows. The Company adopted this standard on July 1, 2019 on a retrospective basis. The adoption of this ASU did not have a material impact on the Company’s consolidated cash flow presentation.

 

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business by adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of a business. This ASU provides a screen to determine when a set of assets is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. If the screen is not met, this ASU (1) requires that to be considered a business, a set of assets must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) removes the evaluation of whether a market participant could replace the missing elements. The Company adopted this standard effective July 1, 2019. The adoption did not have a material impact on the Company’s consolidated financial statements.

 

Accounting Standards Not Yet Adopted

 

In February 2016, the FASB Issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. This ASU is to be adopted using a modified retrospective approach. In May 2020, the FASB elected to defer the effective date for private companies to fiscal years beginning after December 15, 2021 and for interim periods within fiscal years beginning after December 15, 2022. The Company is currently evaluating the effect that adopting this guidance will have on its consolidated financial statements.

 

 

Accounting Estimates

 

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. The most significant estimates pertain to natural gas reserve quantities and related cash flow estimates that form the basis for (i) the allocation of purchase price to evaluated and unevaluated properties, (ii) calculation of depreciation, depletion and amortization (DD&A) of natural gas properties, and (iii) the full cost ceiling test. Management emphasizes that reserve estimates are inherently imprecise and that estimates of reserves of non-producing properties and more recent discoveries are more imprecise than those for properties with long production histories. Other significant estimates include (a) estimated quantities and prices of natural gas sold but not collected, as of period-end; (b) accruals of capital and operating costs; (c) current asset retirement costs, settlement date, inflation rate and credit-adjusted-risk-free rate used in estimating asset retirement obligations; (d) assumptions and calculation techniques used in estimating the fair value of derivative financial instruments, as considered in Note 6; and (e) estimates of expenses related to legal, environmental and other contingencies, as considered in Note 5. Actual results could differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

 

Significant Accounting Policies

 

Cash and Cash Equivalents

 

The Company considers cash equivalents to include all cash items, such as time deposits and short-term investments, including money market accounts, which mature in three months or less from the time of purchase.

 

Accounts Receivable

 

Accounts receivable consist of uncollateralized natural gas revenues due under normal trade terms, as well as joint interest billings due from working interest owners of natural gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. There was no valuation allowance as of June 30, 2020 and 2019.

 

Natural Gas Producing Activities

 

The Company follows the full cost method of accounting for natural gas properties. Under the full cost method, all costs associated with property acquisition, exploration, and development activities are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, cost of drilling, completing and equipping successful and unsuccessful natural gas wells and direct internal costs. Sales or other dispositions of natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

 

The capitalized costs of natural gas properties, plus estimated future development costs relating to proved reserves and estimated cost of dismantlement and abandonment are amortized on a unit-of-production method over the estimated productive life of the proved natural gas reserves. Unevaluated natural gas properties are excluded from this calculation. DD&A expense for the Company’s natural gas properties totaled approximately $170.9 million, $157.4 million and $157.2 million for the years ended June 30, 2020, 2019 and 2018, respectively.

 

Capitalized natural gas property costs are limited to an amount (the ceiling limitation) equal to the sum of the following:

 

	a)	The present value of estimated future net revenues from the projected production of proved natural gas reserves, calculated using the twelve-month average of the first-day-of-the-month prices adjusted for location and quality differentials during the fiscal year (with consideration of price changes only to the extent provided by contractual arrangements) and a discount factor of 10%;
	b)	The cost of investments in unevaluated properties excluded from the costs being amortized; and
	c)	The lower of cost or estimated fair value of unevaluated properties included in the costs being amortized.

 

  

When it is determined that natural gas property costs exceed the ceiling limitation, an impairment charge is recorded to reduce carrying value to the ceiling limitation. For the year ended June 30, 2020, the Company recorded an impairment expense of approximately $139.1 million primarily due to a decrease in prices from $3.018 per MMBTU in 2019 to $2.066 per MMBTU in 2020. For the years ended June 30, 2019 and 2018, the ceiling with respect to the Company’s domestic natural gas properties exceeded the net capitalized costs by more than 100% and 35%, respectively, and the Company did not record an impairment.

 

The costs of certain unevaluated leasehold acreage and certain wells being drilled are not amortized. The Company excludes all costs until proved reserves are found or until it is determined that the costs are impaired. Costs not amortized are periodically assessed for possible impairments or reductions in value. If an impairment is indicated, the amount is charged to the full cost pool, where it is subject to depletion and the ceiling limitation. Sales or other dispositions of unevaluated leasehold acreage are accounted for as adjustments to capitalized costs, with no gain recorded unless the proceeds exceed the carrying value of the related property.

 

Asset Retirement Obligations

 

The fair value of asset retirement obligations is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The fair value of the asset retirement obligations is measured using expected future cash outflows adjusted for inflation and discounted to net present value at the Company’s credit-adjusted risk-free interest rate. Given the unobservable nature of the inputs, the initial measurement of the obligation is considered to be a non-recurring Level 3 fair value estimate. As discussed in “Fair Value Measurements and Fair Value of Financial Instruments,” Level 3 inputs are unobservable inputs based on the Company’s assumptions used to measure assets and liabilities at fair value. The liability is accreted to its then present value each period, and the capitalized cost is depleted or amortized over the estimated recoverable reserves using the units-of-production method. If the liability is settled for an amount other than the recorded amount, the variance is recorded to the full cost pool.

 

The following table is a reconciliation of the asset retirement obligations for the years ended June 30, 2020, 2019 and 2018:

 

		(Amounts in Thousands)
Asset retirement obligations at July 1, 2017		$	13,927
Liabilities incurred			147
Liabilities assumed in business acquisitions			1,618
Accretion expense			1,242
Asset retirement obligations at June 30, 2018			16,934
Liabilities incurred			1,396
Liabilities settled			(802	)
Accretion expense			1,433
Asset retirement obligations at June 30, 2019			18,961
Liabilities incurred			1,107
Liabilities settled			(160	)
Accretion expense			1,618
Asset retirement obligations at June 30, 2020		$	21,526

 

Other Property and Equipment

 

Other property and equipment are carried at cost. Depreciation is calculated using the straight-line method over estimated useful lives that range between 3 to 15 years. Gain or loss on retirement, sale, or other disposition of these assets is included in income in the period of disposition. Costs of major repairs that extend the useful life are capitalized and depreciated over the estimated remaining useful life of the asset. Costs for maintenance and repairs are expensed as incurred. Depreciation and amortization expense for the Company’s other property and equipment totaled approximately $0.6 million, $0.8 million and $0.6 million for the years ended June 30, 2020, 2019 and 2018, respectively.

 

 

Deferred Financing Costs

 

The Company capitalizes certain direct costs associated with the issuance of long-term debt, which is then amortized over the lives of the respective debt using the straight-line method, which approximates the interest method. The amortization of deferred financing cost is recognized in interest expense, net and other in the Company’s consolidated statements of income. Deferred financing costs are recorded as a direct deduction from the carrying amount of long-term debt.

 

Deferred Offering Costs

 

The Company incurred certain offering costs in connection with obtaining capital commitments from various third-party investors and reflected as a direct reduction of members’ equity upon funding of capital commitments.

 

Fair Value Measurements and Fair Value of Financial Instruments

 

U.S. GAAP defines fair value, establishes a framework for measuring fair value and explains the related disclosure requirements. U.S. GAAP indicates, among other things, that a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability and defines fair value based upon an exit price model.

 

U.S. GAAP establishes a valuation hierarchy under Accounting Standards Codification (ASC) 820 for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. Level 3 inputs are unobservable inputs based on the Company’s assumptions used to measure assets and liabilities at fair value. A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

 

The Company’s financial instruments include cash and cash equivalents, accounts receivable, accounts payable, long-term debt and derivative instruments. The recorded value of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value based on their short-term nature. The carrying value of long-term debt approximates fair value as the associated interest rate approximates current market rates. The estimated fair values of the derivatives have been determined using available market data and valuation methodologies (see Note 6).

 

Concentration and Credit Risk

 

The Company’s operations are concentrated in the Marcellus shale formation. This concentration of purchasers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Additionally, factors adversely affecting the oil and gas exploration and production industry could adversely affect the Company and its customers. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

 

The purchasers of the Company’s marketed natural gas production consist primarily of independent marketers, major and independent oil and natural gas companies and gas pipeline companies. During the year ended June 30, 2020, two individual purchasers each accounted for more than 10% of the Company’s total marketed sales for the year: Sequent Energy Management, L.P. (15%) and PSEG Energy Resources & Trade LLC (12%). Natural gas sales receivable due from two purchasers individually accounted for more than 10% of the Company’s natural gas sales receivables as of June 30, 2020: Sequent Energy Management, L.P. (16%) and PSEG Energy Resources & Trade LLC (13%). During the year ended June 30, 2019, two individual purchasers each accounted for more than 10% of the Company’s total marketed sales for the year: Anadarko Energy Services Company (20%) and Sequent Energy Management, L.P. (15%). Natural gas sales receivable due from four purchasers individually accounted for more than 10% of the Company’s natural gas sales receivable as of June 30, 2019: Anadarko Energy Services Company (13%), Mercuria Energy America, Inc. (12%), PSEG Energy Resources & Trade LLC (13%), and Sequent Energy Management, L.P. (12%). For the year ended June 30, 2018, three individual purchasers each accounted for more than 10% of the Company’s total marketed sales for the year: Anadarko Energy Services Company (24%), Sequent Energy Management, L.P. (16%), and Castleton Commodities Merchant Trading (11%).

 

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable and derivative financial instruments. The credit risk associated with the receivables and derivative financial instruments are mitigated by monitoring customers’ and counterparties’ creditworthiness. The Company does not believe that the loss of any of these customers would have a material adverse effect because alternative customers are readily available.

 

 

Additionally, the Company places cash and cash equivalents with high quality financial institutions and at times may exceed the federally insured limits. The Company has not experienced a loss in such accounts nor does it expect any related losses in the near-term.

 

Revenue Recognition

 

On July 1, 2019, the Company adopted ASC 606, Revenue from Contracts with Customers, using the modified retrospective method applied to those contracts which were not completed as of July 1, 2019. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. Results for reporting periods beginning after July 1, 2019 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods.

 

Natural Gas Sales

 

The Company applies the sales method of accounting for natural gas revenue. Natural gas sales revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. The Company markets the majority of its natural gas production, both operated and non-operated taken in kind. An immaterial portion of its non-operated production not taken in kind is marketed by third party operators.

 

The Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point. Consideration received is typically priced at or near the applicable published natural gas index price for the producing area from the purchaser, or, when applicable, at various delivered locations applicable to Company’s natural gas transportation contracts. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The Company evaluated whether it was the principal or the agent in the transaction and concluded the Company is the principal as the ultimate third party is its customer and revenue is recognized on a gross basis, with gathering, compression and transportation fees presented as an expense.

 

Under the sales method, revenues are recognized based on the actual volume of natural gas sold to purchasers. The Company and other joint owners may sell more or less than their entitled share of production. Production volume is monitored to minimize these natural gas imbalances. Over and under deliveries are recorded when future estimated reserves are not adequate to cover the imbalance. As of June 30, 2020 and 2019, there is no asset or liability recorded for imbalances.

 

Marketing

 

AEM buys natural gas utilizing separate purchase transactions, generally with separate counterparties and subsequently sells that natural gas under separate contracts or under its existing contracts. In these arrangements, AEM takes control of the natural gas purchased prior to delivery. Revenues and expenses related to these transactions are reported gross in accordance with applicable accounting standards. Revenues related to these activities are presented in Marketing revenues.

 

Midstream

 

AMM has interests in certain gathering systems that provide gathering, transportation and compression services to AEM as well as third parties. AMM receives and gathers shipper (customer) gas from specified receipt points to the delivery point(s) specified under each agreement. In addition, compression services may be provided on an as needed basis. These agreements are typically interruptible and usage- based such that third-party customers pay an agreed upon rate per MMBtu subject to gathering or compression, which are accounted for as Midstream revenues.

 

Certain of the gathering systems which serve the Company’s operating area are operated by the Company but are not wholly owned. AMM owns 50% of these certain gathering systems and does not receive additional revenues as operator of these gathering systems. AMM and the other co-owners in these systems share in revenues, operating costs and capital expenditures in proportion to their respective ownership interests. Revenues related to these activities are presented in Midstream revenues. The gathering, compression and transportation fees are presented as Gathering, transportation and compression expense. Any amounts recovered from co-owners in respect of their share of operating or capital costs are offset against the related expense such that Alta reports only its net share, consistent with proportionate consolidation guidance.

 

 

Income Taxes

 

The Company elected to be taxed as a partnership for federal income tax purposes and therefore is not subject to federal income taxes. The members are liable for the federal income taxes attributable to their allocable share of the Company’s taxable income. The Company had no state income tax expense during the years ended June 30, 2020, 2019 and 2018, respectively, related to its operations in the states of Texas and Pennsylvania.

 

As of June 30, 2020, the Company had no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits. The Company does not expect that the amounts of unrecognized tax benefits will change significantly within the next 12 months. The Company’s policy is to recognize interest related to any unrecognized tax benefits as interest expense and penalties as operating expenses, and the Company did not incur any such interest from unrecognized tax benefits or penalties during the years ended June 30, 2020, 2019 and 2018.

 

All of the Company’s tax returns filed since its inception date are subject to audit by federal or state tax authorities. For tax years beginning on or after June 30, 2019, the Company is subject to partnership audit rules enacted as part of the Bipartisan Budget Act of 2015 (the Centralized Partnership Audit Regime). Under the Centralized Partnership Audit Regime, any IRS audit of the Company would be conducted at the Company level, and if the IRS determines an adjustment, the default rule is that the Company would pay an “imputed underpayment” including interest and penalties, if applicable. The Company may instead elect to make a “push-down” election, in which case the partners for the year that is under audit would be required to take into account the adjustments on their own personal income tax returns. In the event of an examination of the Company’s tax return, the tax liability of the member could be changed if an adjustment in the Company’s income is ultimately sustained by the taxing authorities. If the Company received an imputed underpayment notice, a determination will be made based on the relevant facts and circumstances that exist at the time. Any payments that the Company ultimately makes on behalf of its current partners will be reflected as a dividend, rather than tax expense at the time such dividend is declared.

 

Note 2 — Acquisitions of Natural Gas Properties

 

Southwestern

 

On June 13, 2019, the Company completed the acquisition of certain Marcellus Shale assets from SWN Production Company, LLC (Southwestern) for an initial purchase price of approximately $25.0 million, subject to normal and customary purchase price adjustments. The Company accounted for this acquisition as an asset purchase and recorded these assets as evaluated properties.

 

Note 3 — Long-Term Debt

 

Long-term debt consisted of the following as of June 30:

 

		2020				2019
		(Amounts in Thousands)
Revolving line of credit		$	509,355			$	522,500
Senior secured second lien notes			102,274				109,067
Total long-term debt			611,629				631,567
Less: deferred financing costs			(7,474	)			(10,441	)
LONG-TERM DEBT, net		$	604,155			$	621,126

 

Maturities of long-term debt at June 30, 2020 are as follows (in thousands):

 

2021		$	—
2022		—
2023		—
2024			611,629
TOTAL		$	611,629

 

 

Credit Agreement

 

Effective April 24, 2020, AMD amended its secured revolving credit agreement (the Revolving Credit Facility) to increase the range of applicable margins for ABR Loans and Eurodollar Loans and modify certain covenants. The Revolving Credit Facility provides a facility with a $1.25 billion commitment and a borrowing base of $800.0 million as of June 30, 2020. The borrowing base can be re-determined on a semi-annual basis, October and April, (a Scheduled Redetermination) or as may be requested one time in between each Scheduled Redetermination by the Lenders or the Company. To the extent that the borrowing base is re-determined at an amount that is below the amount currently outstanding, AMD has options under the Revolving Credit Facility including repayment of the amount borrowed above the re-determined borrowing base over a period of up to six months, provision of additional collateral equal to the amount borrowed above the re-determined borrowing base, or other alternatives as negotiated with the Lenders. The Revolving Credit Facility has a maturity date of the earlier of (a) March 31, 2024 or (b) to the extent any Permitted Second Lien Debt is outstanding as of such date, the date that is one hundred eighty (180) days prior to the earliest maturity date in respect of any such Permitted Second Lien Debt.

 

The obligations under the Revolving Credit Facility and guarantees of those obligations are secured by substantially all of AMD’s assets. Under the Revolving Credit Facility, AMD may also obtain letters of credit, the issuance of which would reduce a corresponding amount available for borrowing. As of June 30, 2020 and 2019, the amount borrowed under the Revolving Credit Facility was $509.4 million and $522.5 million, the value of letters of credit issued under the Revolving Credit Facility was $25.9 million for both periods, and the amount remaining available for borrowing was $264.8 million and $251.6 million, respectively.

 

Pursuant to the Revolving Credit Facility agreement, interest on borrowings are calculated using either the Alternate Base Rate plus an applicable margin for Alternate Base Rate Loans (ABR Loans) or the adjusted London Interbank Offered Rate (LIBOR) over a term elected by AMD plus an applicable margin for Eurodollar Loans. The Alternate Base Rate is defined as the greater of (a) the prime rate established by the Administrative Agent, (b) the federal funds rate in effect plus 0.50% and (c) the daily one-month LIBOR plus 1.00%. The amendment increased the range of applicable margins for ABR Loans and Eurodollar Loans to a range of 2.50% to 3.50% from a range of 2.00% to 3.00%. The specific applicable margin used to determine the rate of each loan is based upon the current utilization of the borrowing base. In addition to interest, the banks receive various fees, including a commitment fee on the unutilized borrowing base. The commitment fee was also amended to be 0.500% per annum at all times, compared to 0.500% per annum if greater than 50% of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized previously. The Company had no ABR Loans outstanding as of June 30, 2020 and 2019. The weighted-average interest rate on loan amounts outstanding under the Revolving Credit Facility as of June 30, 2020 and 2019, was 3.18% and 4.81%, respectively.

 

The Revolving Credit Facility contains certain financial covenants typical for these types of agreements, including current ratio and total debt to EBITDAX (as defined in the Credit Agreement) ratio. Pursuant to the amendment of the Revolving Credit Facility, certain covenants were modified or added, as follows:

 

	•	Maintenance of the consolidated leverage covenant was reduced from 4.0x debt / EBITDA to 3.5x debt / EBITDA.
	•	The restricted payments test was amended from 3.0x debt / EBITDA to 2.5x debt / EBITDA.
	•	Addition of certain industry anti-cash hoarding provisions, including requiring prepayment of excess cash over certain thresholds first to any ABR Borrowings outstanding then ratably to Eurodollar Borrowings then outstanding.

 

As of June 30, 2020, AMD was in compliance with all of its financial covenants under the Revolving Credit Facility.

 

Senior Secured Second Lien Notes

 

On March 31, 2017, AMD closed $300 million aggregate principal amount of 7.75% Senior Secured Second-Priority Notes due March 31, 2024 (the Senior Secured Second Lien Notes) in a private offering pursuant to an indenture dated as of March 31, 2017 (the Senior Secured Second Lien Notes Indenture). The obligations under the Senior Secured Second Lien Notes and guarantees of those obligations are secured by substantially all of AMD’s assets.

 

The Senior Secured Second Lien Notes are guaranteed by AMD’s subsidiary guarantors Alta Marcellus Midstream, LLC and Alta Energy Marketing, LLC. Interest accrues at the rate of 7.75% per annum and is payable quarterly in arrears on March 30, June 30, September 30 and December 30 of each year during the term. The amount outstanding on the Senior Secured Second Lien Notes was $102.3 million and $109.1 million on June 30, 2020 and 2019, respectively. The covenants and events of default under AMD’s Senior Secured Second Lien Notes Indenture are substantially similar to the Revolving Credit Facility, with the exception of the following. In May 2019, the Company amended the Senior Secured Second Lien Notes to reduce its hedging covenant from two years to one year, for 65% of proved developed producing reserves, while the Revolving Credit Facility does not have a hedging obligation. On June 30, 2020, AMD was in compliance with all of its financial covenants under the Senior Secured Second Lien Notes Indenture.

 

 

Note 4 — Members’ Equity

 

Pursuant to the limited liability company agreement dated July 24, 2015, as amended, (the LLC Agreement), the Company has an initial term of ten years, and the Board of Managers shall have the right to extend the term of the Company for additional successive extensions of two years by approval of the Company’s Membership Advisory Committee (MAC), as determined in the LLC Agreement.

 

The Company has three classes of membership interests consisting of Class A, Class B, and Class C. Each of Class A and Class B members may vote in proportion to their respective ownership percentage as of a predetermined date of record. Class A members have the authority to appoint members to the Company’s Board of Managers upon majority of Class A member’s approval, provided, however, unless otherwise approved by the MAC, the Operator Key Persons as defined in the LLC Agreement shall serve on the Board. Distributions of available cash shall be made in accordance with the LLC Agreement. The Class C membership interest holder is entitled to distributions only after Class A and Class B members have received their respective distributions as defined in the LLC Agreement. Profits and losses of the Company are allocated to its members pursuant to the LLC Agreement. The Class C membership interest is non-voting and constitutes Profits Interests in accordance with Internal Revenue Code.

 

As of June 30, 2020, the Company had aggregate capital contributions from various institutional investors of approximately $816.0 million with no further capital contribution commitments remaining. Members’ liabilities are limited to their capital contributions. As of June 30, 2020, the Company had made aggregate cash distributions of approximately $520.7 million to its investors.

 

Note 5 — Commitments and Contingencies

 

Commitments

 

Operating Leases — In July 2017, the Company entered into an office space lease in Houston, Texas under a non-cancelable operating lease, which expires in January 2029. In addition, the Company has a field office and several other leases in Pennsylvania to support its field operations; these non-cancellable operating leases have expiration dates up to December 2024.

 

Future minimum lease payments through 2029 under the non-cancellable operating leases as of June 30, 2020 are as follows (in thousands):

 

Years Ending June 30,
2021		$	1,624
2022			1,424
2023			1,444
2024			1,465
2025			1,236
Thereafter			4,434
TOTAL		$	11,627

 

The Company incurred approximately $1.3 million, $1.5 million and $1.3 million in rent expense for the years ended June 30, 2020, 2019 and 2018, respectively.

 

Firm Transportation — The Company has access to firm transportation capacity to delivered pricing locations that have historically priced higher than Marcellus in-basin prices. The Company believes it will have sufficient production quantities to meet substantially all of its commitments but may be required to purchase natural gas from third parties to satisfy shortfalls should they occur.

 

 

 

A summary of the Company’s future minimum obligations under transportation agreements as of June 30, 2020 are as follows (in thousands):

 

Years Ending June 30,
2021		$	24,229
2022			20,745
2023			11,985
2024			7,159
2025			7,159
Thereafter			16,705
TOTAL		$	87,982

 

Demand Charges — The Company is obligated under certain of these firm transportation arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. Pursuant to these agreements, the Company must pay annual demand charges of approximately $12.3 million; these agreements expire between October 2028 and November 2033.

 

Delivery Commitments — The Company has natural gas sales agreements that have minimum delivery commitments ranging from 13,500 MMBtu per day to 54,000 MMBtu per day and expire between October 2021 and October 2033. The Company believes it is able to fulfill these contractual obligations from its own production; however, third party volumes may be purchased to satisfy these commitments.

 

Contingencies

 

There are currently various suits and claims pending against Anadarko for which the Company owes an obligation of indemnity that has arisen in the ordinary course of business, including contract disputes, property damage claims and title disputes. Management believes that the resolution of these suits and claims will not, individually or in the aggregate, have a material effect on the Company’s consolidated financial position, results of operations or cash flow. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

 

Note 6 — Risk Management Activities

 

The Company has entered into various derivative contracts to manage its exposure to natural gas price fluctuations on a portion of its anticipated future production volumes for the years 2021 through 2023. These derivatives include natural gas price swaps and basis differential swaps. The Company’s commodity derivative instruments generally serve as effective economic hedges of commodity risk exposure; however, the Company has elected not to account for the derivatives as cash flow hedges. As such, the Company recognizes all changes in fair value of its commodities derivatives in net gain (loss) on price risk management activities in revenues in its consolidated statements of income. The resulting cash flows are reported as cash flows from operating activities.

 

The Company also entered into various derivative contracts to hedge the impact of market fluctuations in LIBOR, which is the floating rate that applies to the borrowings under the Revolving Credit Facility. As of June 30, 2020, the Company has $225 million LIBOR swaps outstanding, which represents a portion of the expected Revolving Credit Facility balance through its remaining term. The Company’s interest rate derivative instruments generally serve as effective economic hedges of interest rate risk exposure; however, the Company has elected not to account for the derivatives as cash flow hedges. As such, the Company recognizes all changes in fair value of its interest rate derivatives in net gain (loss) on interest rate derivatives on its consolidated statements of income.

 

The following tables provide the assets and liabilities carried at fair value measured on a recurring basis as of June 30, 2020 and 2019.

 

 

Assets (Liabilities) Measured at Fair Value on a Recurring Basis

 

		Quoted in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Balance
		(Amounts in thousands)
June 30, 2020
Commodity swaps		$	—			$	28,747			$	—			$	28,747
Basis swaps		$	—			$	(3,445	)		$	—			$	(3,445)
Interest rate swaps		$	—			$	(17,830	)		$	—			$	(17,830	)

  

		Quoted in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Balance
		(Amounts in thousands)
June 30, 2019
Commodity swaps		$	—			$	44,955			$	—			$	44,955
Basis swaps		$	—			$	(26,929	)		$	—			$	(26,929	)
Interest rate swaps		$	—			$	(6,673	)		$	—			$	(6,673	)

  

The Company had the following commodity and interest rate derivatives outstanding:

 

		Asset Derivatives						Liability Derivatives
As of June 30, 2020		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
		(Amounts in thousands)
Current
Commodity contracts		Assets from risk management activities		$	37,544			Liabilities from risk management activities		$	(2,700	)
Interest rate contracts		Assets from risk management activities			—			Liabilities from risk management activities			(5,111	)
					37,544						(7,811	)
Non-current
Commodity contracts		Assets from risk management activities			290			Liabilities from risk management activities			(9,832	)
Interest rate contracts		Assets from risk management activities			—			Liabilities from risk management activities			(12,719	)
					290						(22,551	)
TOTAL DERIVATIVES				$	37,834					$	(30,362	)

 

 

		Asset Derivatives						Liability Derivatives
As of June 30, 2019		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
		(Amounts in thousands)
Current
Commodity contracts		Assets from risk management activities		$	30,783			Liabilities from risk management activities		$	(15,853	)
Interest rate contracts		Assets from risk management activities			—			Liabilities from risk management activities			(1,089	)
					30,783						(16,942	)
Non-current
Commodity contracts		Assets from risk management activities			6,140			Liabilities from risk management activities			(3,044	)
Interest rate contracts		Assets from risk management activities			—			Liabilities from risk management activities			(5,584	)
					6,140						(8,628	)
TOTAL DERIVATIVES				$	36,923					$	(25,570	)

 

The following tables present the gross asset and liability balances of the Company’s commodity derivative instruments, the amounts subject to master netting arrangements, and the amounts presented on a net basis:

 

		As of June 30,
		2020				2019
			(Amounts in thousands)
Commodity Derivative Assets
Gross amounts of recognized assets		$	107,681			$	45,776
Gross amounts offset in the consolidated balance sheets			(69,847	)			(8,853	)
Net amount of assets presented in the consolidated balance sheets		$	37,834			$	36,923
Commodity Derivative Liabilities
Gross amounts of recognized liabilities		$	(82,379	)		$	(27,750	)
Gross amounts offset in the consolidated balance sheets			69,847				8,853
Net amount of liabilities presented in the consolidated balance sheets		$	(12,532	)		$	(18,897	)

 

 

The Company recognized the following commodity and interest rate derivative activities during the years ended June 30, 2020, 2019 and 2018, respectively.

 

		For the Years Ended June 30,
Location of Gain (Loss) Recognized on Statements of Income		2020				2019				2018
		(Amounts in thousands)
Revenue
Cash received (paid) on settlement of derivative instruments
(Loss) gain on derivative instruments		$	96,440			$	(57,195	)		$	7,086
Non-cash gain (loss) on derivative instruments
Gain on derivative instruments			7,276				52,373				6,903
Net gain (loss) on price risk management activities		$	103,716			$	(4,822	)		$	13,989
Other Income (Expense)
Cash received (paid) on settlement of derivative instruments
(Loss) gain on derivative instruments		$	(1,629	)		$	58			$	(56	)
Non-cash gain (loss) on derivative instruments
Gain (loss) on derivative instruments			(11,157	)			(7,157	)			483
Net gain (loss) on interest rate derivatives		$	(12,786	)		$	(7,099	)		$	427

 

Open commodity price derivative contracts as of June 30, 2020 by fiscal year are as follows:

 

		Range of Price			Quantity (MMBTU)
Instrument Type		$/MMBTU			2021			2022				2023				Total				Fair Value
																				(Amounts in thousands)
Swap		$2.19 – $2.54			905,000				920,000				—				1,825,000			$	(494	)
Swap		$2.17 – $2.97			24,675,000				10,120,000				—				34,795,000				6,104
Swap		$2.18 – $2.80			6,410,000				1,840,000				—				8,250,000				1,371
Swap		$2.17 – $3.09			9,065,000				9,185,000				920,000				19,170,000				(138	)
Swap		$2.07 – $2.95			22,947,600				5,520,000				—				28,467,600				8,200
Swap		$2.14 – $2.97			4,555,000				2,760,000				—				7,315,000				(102	)
Swap		$2.23 – $3.10			5,460,000				3,680,000				—				9,140,000				720
Swap		$2.18 – $2.97			11,885,000				4,600,000				—				16,485,000				2,633
Swap		$2.18 – $3.09			19,577,054				13,340,000				—				32,917,054				(732	)
Swap		$2.19 – $3.09			5,445,000				4,600,000				—				10,045,000				(381	)
Swap		$2.10 – $3.09			22,835,000				11,025,000				920,000				34,780,000				6,586
Swap		$2.14 – $3.09			17,994,200				7,360,000				—				25,354,200				4,980
					151,753,854				74,950,000				1,840,000				228,543,854			$	28,747

 

 

Open commodity price derivative contracts as of June 30, 2019 by fiscal year are as follows:

 

		Range of Price			Quantity (MMBTU)
Instrument Type		$/MMBTU			2020				2021				2022				Total				Fair Value
																					(Amounts in thousands)
Swap		$2.67 – $2.94			5,663,110				—				—				5,663,110			$	2,168
Swap		$2.46 – $3.20			15,329,647				11,945,000				920,000				28,194,647				6,643
Swap		$2.48 – $3.15			6,997,036				1,840,000				—				8,837,036				2,513
Swap		$2.53 – $3.10			19,986,566				10,730,000				—				30,716,566				7,771
Swap		$2.44 – $2.91			1,820,000				2,745,000				920,000				5,485,000				439
Swap		$2.51 – $3.15			27,926,265				5,520,000				—				33,446,265				10,316
Swap		$2.47 – $2.94			5,641,092				2,759,554				920,000				9,320,646				1,617
Swap		$2.46 – $3.19			19,930,809				11,945,000				920,000				32,795,809				8,388
Swap		$2.52 – $3.11			11,030,351				7,994,200				—				19,024,551				5,100
					114,324,876				55,478,754				3,680,000				173,483,630			$	44,955

  

Open basis price derivative contracts as of June 30, 2020 by fiscal year are as follows: 

 

		Range of Price		Quantity (MMBTU)
Instrument Type		$/MMBTU		2021				2022				2023				Total				Fair Value
																					(Amounts in thousands)
Basis Swap		$(0.77) – $(0.38)			7,677,600				1,840,000				—				9,517,600			$	(601	)
Basis Swap		$(0.56) – $2.82			6,100,000				1,840,000				—				7,940,000				(3	)
Basis Swap		$(0.82) – $(0.38)			8,175,000				7,345,000				920,000				16,440,000				(158	)
Basis Swap		$(0.96) – $4.45			33,815,000				14,705,000				920,000				49,440,000				(2,810	)
Basis Swap		$(0.77) – $(0.39)			5,460,000				3,680,000				—				9,140,000				(30	)
Basis Swap		$(0.79) – $4.61			32,510,000				12,880,000				—				45,390,000				(217	)
Basis Swap		$(0.89) – $3.75			26,337,054				13,340,000				—				39,677,054				231
Basis Swap		$(0.79) – $4.54			20,875,000				17,480,000				—				38,355,000				1,717
Basis Swap		$(0.62) – $4.94			21,764,200				1,840,000				—				23,604,200				(1,574	)
					162,713,854				74,950,000				1,840,000				239,503,854			$	(3,445	)

 

Open basis price derivative contracts as of June 30, 2019 by fiscal year are as follows:

 

		Range of Price			Quantity (MMBTU)
Instrument Type		$/MMBTU			2020			2021				2022				Total				Fair Value
																					(Amounts in thousands)
Basis Swap		$(0.90) – $(0.36)			12,840,000				3,680,000				—				16,520,000			$	(2,511	)
Basis Swap		$(0.92) – $2.82			34,026,440				5,195,000				920,000				40,141,440				(8,181	)
Basis Swap		$0.22 – $0.96			28,895,515				13,800,000				—				42,695,515				(6,656	)
Basis Swap		$(0.79) – $1.23			14,740,000				14,305,000				920,000				29,965,000				(119	)
Basis Swap		$(0.89) – $(0.04)			9,745,341				2,774,554				—				12,519,895				(1,498	)
Basis Swap		$(0.62) – $4.94			20,074,600				21,764,200				1,840,000				43,678,800				(7,964	)
					120,321,896				61,518,754				3,680,000				185,520,650			$	(26,929	)

  

 

 Open interest rate derivative contracts as of June 30, 2020 are as follows:

 

Instrument Type		Range of Fixed Rates		Notional Amount				From		To		Fair Value
					(Amounts in thousands)								(Amounts in thousands)
1 Month LIBOR Swap		2.12 – 2.73%		$	225,000			7/1/2020		3/31/2021		$	(3,810	)
1 Month LIBOR Swap		2.12 – 2.74%		$	225,000			4/1/2021		3/31/2022			(5,214	)
1 Month LIBOR Swap		2.12 – 2.13%		$	225,000			4/1/2022		3/31/2023			(4,543	)
1 Month LIBOR Swap		2.12 – 2.13%		$	225,000			4/1/2023		3/31/2024			(4,263	)
												$	(17,830	)

 

Open interest rate derivative contracts as of June 30, 2019 are as follows:

 

Instrument Type		Range of Fixed Rates		Notional Amount				From		To		Fair Value
					(Amounts in thousands)								(Amounts in thousands)
1 Month LIBOR Swap		2.12 – 2.58%		$	225,000			7/1/2019		3/31/2020		$	(642	)
1 Month LIBOR Swap		2.12 – 2.73%		$	225,000			4/1/2020		3/31/2021			(2,075	)
1 Month LIBOR Swap		2.12 – 2.74%		$	225,000			4/1/2021		3/31/2022			(1,885	)
1 Month LIBOR Swap		2.12 – 2.13%		$	225,000			4/1/2022		3/31/2023			(1,179	)
1 Month LIBOR Swap		2.12 – 2.13%		$	225,000			4/1/2023		3/31/2024			(892	)
												$	(6,673	)

  

Note 7 — Employee Benefits

 

401(K) Plan

 

Effective July 1, 2017, the Company adopted a defined contribution plan (the Benefit Plan) that complies with Section 401(k) of the Internal Revenue Code. All employees are eligible to participate immediately upon date of hire, and all participants are eligible for the employer non-discretionary match at 100%, up to 6% of a participant’s eligible compensation. Participants may elect voluntary salary deferral contributions withheld from their salary based on an elected percentage of up to 100%, subject to annual individual statutory deferral limitations. Participants are immediately vested in their elective contributions and employer non-discretionary matching plus actual earnings thereon. Vesting in the employer’s discretionary contribution portion of their accounts prior plus actual earnings thereon is based on years of credited service. For employer’s discretionary contributions, participants are vested immediately upon completing three full years of service. Upon separation, participants are entitled to the vested portion of their accounts. Employer contribution expense for the years ended June 30, 2020, 2019 and 2018 was approximately $1.0 million, $1.0 million and $0.7 million, respectively, and recorded in general and administrative expense.

 

Long-Term Incentive Plan

 

Effective October 31, 2018, Alta Resources, LLC, a member of Alta Resources Holdings, LLC (Class C member), adopted a long term incentive plan (the LTIP Plan) to award and retain employees of the Company by providing participating employees with an opportunity to receive additional compensation in connection with the future success of the Company, by providing a Phantom Unit. A Phantom Unit is defined in the LTIP Plan as a notional unit that, once vested, permits the holder to receive the applicable Distribution Value and/or Unit Value (two award components). Phantom Units vest in three ratable, annual installments beginning on the first anniversary from the initial date of grant. Vesting is contingent on the participant’s continued employment, with certain exceptions. On a change in control, 100% of any unvested units vest only if the participant continues employment through the date of change in control. Vesting conditions vary with respect to termination cause.

 

The Company accounts for the first component of the award (the Distribution Value) as an in-substance profit-sharing arrangement in accordance with ASC 710, Compensation. No distribution pursuant to the LTIP Plan was declared as of June 30, 2020 and 2019, and therefore no compensation expense was recognized during the years ended June 30, 2020 and 2019.

 

 

The second component of the award (the Unit Value) provides rights to the residual equity interest in the Company, whereby the employee has a put right prior to an ultimate liquidation event for 85% of the then-determined fair value. Additionally, the employee may only sell, in any one calendar year, a maximum of 20% of the greatest number of Phantom Units held by the employee during their employment with the Company or any of its affiliates. Furthermore, a participant may not sell more than 50% in the aggregate of the greatest number of Phantom Units held by the employee during their employment with the Company or any of its affiliates. Vesting is dependent upon: 1) liquidation event or change in control, as defined in the LTIP Plan, and 2) employment condition through the date of liquidation or change in control. The Company accounts for the second component in accordance with ASC 718, Compensation — Stock Compensation, as a liability award. However, as the preceding performance conditions were not considered probable as of the grant date and furthermore not estimable as of June 30, 2020 and 2019, no compensation expense was recognized during the years ended June 30, 2020 and 2019.

 

In May 2020, a portion of these units vested in accordance with the above vesting schedule. The Company opened the sellback window to employees between August 17 through 28, 2020. An immaterial portion of units were sold back to the Company.

 

Note 8 — Revenue from Contracts with Customers

 

Disaggregation of Revenue

 

The Company has identified the major revenue streams within the scope of ASC 606: Natural gas sales, Marketing and Midstream. A detailed summary for each disaggregated category of revenue is below:

 

		Years Ended June 30,
		2020				2019				2018
		(Amounts in thousands)
Revenue from Contracts with Customers
Natural gas revenues		$	448,076			$	684,406			$	483,575
Other operating
Marketing			10,135				4,872				59
Midstream			4,811				4,290				7,043
Total other operating			14,946				9,162				7,102
Total revenue from contracts with customers			463,022				693,568				490,677
Net gain (loss) on commodity risk management activities			103,716				(4,822	)			13,989
Other revenues			271				594				13
Total revenues		$	567,009			$	689,340			$	504,679

 

Transaction Price Allocated to Remaining Performance Obligations

 

A significant number of the Company’s product sales have a contract term of one year or less. For those contracts, the Company has utilized the practical expedient allowed in ASC 606 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

For the Company’s product sales that have a contract term greater than one year, the Company has also utilized the practical expedient waiving the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, the Company’s product sales that have a contractual term greater than one year have no long-term fixed consideration.

 

Contract Balances

 

Under the Company’s sales contracts, it invoices its customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets  or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $37.8 million at June 30, 2020 and $47.8 million at June 30, 2019.

 

 

 

 

Prior−Period Performance Obligations

 

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas sales may be received for one to three months after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended June 30, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

Note 9 — Related Party Transactions

 

On December 20, 2019, the Company executed a $2.4 million Secured Non-Recourse Promissory Note (Note) with Alta Resources Holdings, LLC, a related party, as an advance of Profits Interest. Pursuant to the Note, interest is accrued at 2%. The principal and accrued interest is due upon Alta Resources Holdings, LLC’s receipt of its distributed Class C membership interest. Amounts due from Alta Resources Holdings, LLC are included in note receivable from affiliates and other in the accompanying consolidated balance sheets of approximately $2.4 million as of June 20, 2020.

 

As of June 30, 2020, the Company covered approximately $0.6 million of assets and expenses on behalf of Alta Resources Development II, LLC, a related party, in anticipation of its establishment, which became effective on July 1, 2020. In connection, the Company executed the Management and Administrative Services Agreement (MASA) on July 10, 2020 for administrative support and management functions to evaluate prospective oil and gas properties. Amounts due from Alta Resources Development II, LLC are included in advance to affiliates in the accompanying consolidated balance sheets of approximately $0.6 million as of June 30, 2020.

 

Note 10 — Subsequent Events

 

Management considered subsequent events through September 28, 2020, the date on which the Company’s consolidated financial statements were available for issuance.

 

Note 11 — Natural Gas Producing Activities (Unaudited)

 

The following supplementary information summarized presents the results of natural gas activities in accordance with the full cost method of accounting for production activities.

 

Costs Incurred Related to Natural Gas Operations

 

The following tables present total aggregate capitalized costs and costs incurred related to natural gas production activities.

 

		Years Ended June 30,
		2020				2019				2018
		(Amounts in thousands)
Capitalized costs
Evaluated properties(1)		$	2,074,787			$	1,784,303			$	1,552,914
Unevaluated properties			8,146				7,055				7,141
Total capitalized costs			2,082,933				1,791,358				1,560,055
Less: Accumulated depletion and impairment			(661,327	)			(351,344	)			(193,917	)
Net capitalized costs		$	1,421,606			$	1,440,014			$	1,366,138

 

(1)

Amounts in 2019 include $25.0 million the purchase interests in producing units and undeveloped acreage in Alta’s operated properties from Southwestern Energy. Amounts in 2018 include $116.4 million for the purchase interests in producing units, undeveloped acreage and associated midstream interests in Alta’s operated properties from Ultra Petroleum.

 

 

Results of Operations for Producing Activities

 

The following table presents the results of operations related to natural gas production.

 

		Years Ended June 30,
		2020				2019				2018
		(Amounts in thousands)
Sales of natural gas		$	448,076			$	684,406			$	485,168
Transportation and processing			157,435				144,557				132,019
Lease Operating Expense			39,186				39,644				39,136
Depreciation and depletion			170,921				157,426				157,205
Impairment and expiration of leases			139,063				—				—
Results of operations from producing activities, excluding corporate overhead		$	(58,529	)		$	342,779			$	156,808

 

Reserve Information

 

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.

 

The Company’s estimate of proved natural gas reserves was prepared by Netherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm hired by management. Since 1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. NSAI has estimated 100% of the total net natural gas proved reserves attributable to the Company’s interests as of June 30, 2020, 2019 and 2018 in accordance with the definitions and regulation of the U.S. Securities and Exchange Commission and, with the exception of the exclusion of future income taxes, conform to the FASB ASC No 932, Extractive Activities — Oil & Gas. Standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy and material balance were utilized in the evaluation of reserves. All of the Company’s proved reserves are located in the United States.

 

The engineer primarily responsible for providing Company data necessary for the preparation of the reserves estimate holds a Bachelor of Science degree in Mining Engineering from the National Institute of Technology in India and a Master’s Degree in Petroleum Engineering from the University of Texas at Austin and has 15 years of experience in the oil and gas industry. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; and the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management.

 

		Year ended June 30,
		2020				2019				2018
		(Volumes in Mmcf)
Balance at July 1			3,679,226				2,643,329				2,577,715
Revisions of previous estimates			405,928				784,086				(282,995	)
Extensions, discoveries and other additions			—				248,345				149,680
Acquisitions			—				237,621				381,063
Production			(264,537	)			(234,155	)			(182,134	)
Balance at June 30			3,820,617				3,679,226				2,643,329
Proved developed reserves as of
Balance at July 1			1,737,819				1,654,683				1,450,248
Balance at June 30			1,943,820				1,737,819				1,654,683
Proved undeveloped reserves as of
Balance at July 1			1,941,407				988,646				1,127,467
Balance at June 30			1,876,797				1,941,407				988,646

 

 

The change in reserves during the year ended June 30, 2020 resulted from the following:

 

•

Positive revisions of 405.9 Bcf due primarily to changes in working interests and net revenue interests, adjustments to the development schedule, improved development pacing and type curve updates to reflect well outperformance relative to type curve.

 

The change in reserves during the year ended June 30, 2019 resulted from the following:

 

	•	Extensions, discoveries and other additions of 248.3 Bcfe exceeded 2019 production of 234.2 Bcfe which was primarily due to the eastward expansion of Alta’s Warrensville area within the 5-year window.
	•	Positive revisions of 784.1 Bcf primarily due to outperformance in Alta’s operated area and sufficient data to demonstrate the uplift from Alta’s modern completion approach as compared to the well performance of the prior operator.
	•	Purchase of hydrocarbons in place of 237.6 Bcfe due to the Southwestern Acquisition described in Note 2.

 

The change in reserves during the year ended June 30, 2018 resulted from the following:

 

	•	Extensions, discoveries and other additions of 149.7 Bcf primarily due to proved undeveloped additions associated with acreage that was excluded from prior year proved reserves bookings, but subsequently became proved due to inclusion within the Company’s five-year drilling plan and the completion of certain drilled but uncompleted wells that had not been included in prior report’s 5-year development window.
	•	Negative revisions of 283.0 Bcfe from proved developed locations, due changes in development pace pushing wells out of the 5-year development window.
	•	Purchase of hydrocarbons in place of 381.1 Bcfe due to the Ultra Acquisition.

 

Standard Measure of Discounted Future Cash Flow

 

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

 

The following table summarizes estimated future net cash flows from natural gas and crude oil reserves.

 

		Year ended June 30,
		2020				2019				2018
		(Amounts in thousands)
Future cash flows		$	5,988,487			$	10,030,339			$	6,576,981
Future production costs			(2,052,950	)			(2,444,720	)			(2,013,569	)
Future development costs			(1,040,484	)			(1,137,618	)			(833,393	)
Future net cash flows			2,895,053				6,448,001				3,730,019
10% annual discount for estimated timing of cash flows			(1,520,154	)			(3,540,245	)			(1,882,152	)
Standardized measure of discounted future net cash flows		$	1,374,899			$	2,907,756			$	1,847,867

 

The above cash flows include approximately $122.9 million, $120.4 million and $107.7 million for future plugging and abandonment costs as of June 30, 2020, 2019 and 2018, respectively.

 

For 2020, reserves were computed using gas prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2019 through June 2020. The average Henry Hub spot price of $2.066 per MMBtu was adjusted for energy content, transportation fees, and market differentials. The fees associated with the Company’s firm transportation contracts were included as a deduction to gas revenue. Gas prices were held constant throughout the lives of the properties. The average adjusted gas price weighted by production over the lives of the properties was $1.567 per Mcf.

 

 

For 2019, reserves were computed using gas prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2018 through June 2019. The average Henry Hub spot price of $3.018 per MMBtu was adjusted for energy content, transportation fees, and market differentials. The fees associated with the Company’s firm transportation contracts were included as a deduction to gas revenue. Gas prices were held constant throughout the lives of the properties. The average adjusted gas price weighted by production over the lives of the properties was $2.726 per Mcf.

 

For 2018, reserves were computed using gas prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2017 through June 2018. The average Henry Hub spot price of $2.917 per MMBtu was adjusted for energy content, transportation fees, and market differentials. The fees associated with the Company’s firm transportation contracts were included as a deduction to gas revenue. Gas prices were held constant throughout the lives of the properties. The average adjusted gas price weighted by production over the lives of the properties was $2.488 per Mcf.

 

The following table summarizes the changes in the standardized measure of discounted future net cash flows:

 

		Year ended June 30,
		2020				2019				2018
		(Amounts in thousands)
Net changes in prices, production and development costs		$	(1,802,302	)		$	440,484			$	250,840
Revisions of previous quantity estimates			23,115				630,841				(691	)
Sales and transfers of natural gas and oil produced – net			(251,455	)			(500,205	)			(321,099	)
Accretion of discount			290,776				184,787				132,194
Extensions, discoveries and improved recovery, less related costs			—				169,999				117,931
Acquisitions			—				174,200				296,202
Previously estimated development costs incurred			225,647				35,397				68,282
Timing and other			(18,638	)			(75,614	)			(17,730	)
Net change for the year			(1,532,857	)			1,059,889				525,929
Beginning of year			2,907,756				1,847,867				1,321,938
End of year		$	1,374,899			$	2,907,756			$	1,847,867