EX-99.6

EX-99.6 21 d242119dex996.htm EX-99.6 EX-99.6

Exhibit 99.6

BCP RAPTOR HOLDCO, LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unless the context otherwise requires, all references in this section to “BCP,” “EagleClaw Midstream,” “ECM,” “the Partnership,” “we,” “us,” and “our” refer to BCP Raptor Holdco, LP and its subsidiaries prior to the consummation of the Transaction.

You should read the following discussion and analysis of our financial condition and results of operations together with the audited consolidated financial statements and related notes appearing as Exhibit 99.4 to this Current Report on Form 8-K (“Form 8-K”) and the final proxy statement filed with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 on January 12, 2022 (the “Proxy Statement”). The discussion and analysis should also be read together with the unaudited pro forma condensed consolidated combined financial information appearing as Exhibit 99.5 to this Form 8-K. This discussion contains forward-looking statements that reflect our plans, estimates, and beliefs that involve risks and uncertainties. As a result of many factors, such as those identified in this Form 8-K and those discussed in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” appearing in the Proxy Statement, our actual results may differ materially from those anticipated in these forward-looking statements. Note that terms used, but not defined herein, shall have the meanings set forth in the Proxy Statement.

Overview

BCP Raptor Holdco, LP (“BCP”) is the parent of ECM, which is an integrated midstream energy company operating in the Permian Basin providing comprehensive gathering, transportation, compression, processing, and treating services for companies that produce natural gas, natural gas liquids (“NGLs”), crude oil, and water. BCP is headquartered in Midland, Texas and has a significant presence in Houston, Texas. ECM operates in the Southern Delaware Basin, specifically in Culberson, Loving, Pecos, Reeves, and Ward Counties, Texas. ECM is one of the largest gas processors in the Delaware Basin, with 1,320 million cubic feet per day (“MMcf/d”) of capacity and more than 1,400 miles of operated pipelines. ECM has long-term dedications of approximately 750,000 acres for gas, crude, and water midstream services from nearly 30 successful and active producers in the Delaware Basin.

Our Operations

The Partnership has determined it has two operating segments, which represent its reportable segments: the Gathering and Processing segment and the Transmission segment. The Gathering and Processing segment represents the consolidated operations of the Partnership. The Transmission segment is comprised of the Partnership’s investment in unconsolidated affiliate, Permian Highway Pipeline, LLC (“PHP”) and the Delaware Link Pipeline that is under construction.

Gathering and Processing

The Gathering and Processing segment operates under three entities: EagleClaw Midstream Ventures, LLC (“ECMV”), Pinnacle Midstream, LLC (“Pinnacle”) and CR Permian Holdings, LLC (“CR Permian”). That segment includes gas gathering and compression assets located throughout the Southern Delaware Basin, with approximately 1,000 miles of low and high-pressure steel pipeline. Gas processing assets are centralized at four processing complexes with total cryogenic processing capacity of 1.3 billion cubic feet per day (“Bcf/d”): the East Toyah complex (460 MMcf/d), the Pecos Bend complex (520 MMcf/d), the Pecos complex (260 MMcf/d) and the Sierra Grande complex (60 MMcf/d). Current residue gas outlets include the El Paso Natural Gas Pipeline, ET Comanche Trail Pipeline, Oneok Roadrunner Pipeline, ET Oasis Pipeline and Whitewater Agua Blanca. NGL outlets include Energy Transfer GC NGL Pipeline and Grand Prix Pipeline.

The Gathering and Processing segment also includes ECM’s crude oil gathering, stabilization, and storage services throughout the Texas Delaware Basin. Crude gathering assets are centralized at the Caprock Stampede Terminal and the Pinnacle Sierra Grande Terminal. The system includes approximately 200 miles of gathering pipeline and 90,000 barrels of crude storage. The crude facilities have connections for takeaway transportation into Plains’ 285 Central Station and State Line and Oryx’ Orla & Central Mentone.

Finally, ECM has water gathering and disposal assets located in northern Reeves County, Texas which are included in the Gathering and Processing segment. The system includes approximately 70 miles of gathering pipeline and approximately 500,000 barrels per day of permitted disposal capacity at 16 active and permitted disposal wells.

Transmission

The Transmission segment consists of a 26.67% equity interest in PHP, and the Delaware Link Pipeline that is under construction. PHP was formed to develop, construct, own, operate and maintain the PHP Pipeline. Beginning at the Waha Texas Hub and extending to the U.S. Gulf Coast and Mexico markets, the 430-mile pipeline is designed to transport up to approximately 2.1 Bcf/d of natural gas. The approximately $2.3 billion pipeline project was placed in full commercial service on January 1, 2021.

Refer to the “Information Concerning BCP and EagleClaw Midstream” section of the Proxy Statement for further details on our business.

Factors Affecting Our Business

The Significance of Crude Oil and Producer Volumes on Our Revenues, Cost of Sales and Gross Margin

The Partnership’s assets include more than 1,400 miles of natural gas, NGLs, condensate, and crude oil pipelines as well as 1,320 MMcf/d of natural gas processing capacity which service 750,000 dedicated acres across nearly 30 customers under long-term contracts as of December 31, 2021. All of the gas gathered and processed by the Partnership is associated gas included in the oil stream, making producers’ oil break-even prices the primary driver of activity, not natural gas prices. The average price of West Texas Intermediate (“WTI”) crude oil was $77.11/bbl during the fourth quarter of 2021. If crude prices were to fall below producers’ break-even prices for a prolonged period of time, drilling activity and volumes might decline as we experienced during the second quarter of 2020 as a result of the COVID-19 pandemic.

Recent Developments

Merger with Altus Midstream Company

On October 21, 2021, New BCP Raptor Holdco, LLC (“Raptor Holdco”) as representative of the Partnership’s unitholders, entered into a Contribution Agreement with Altus Midstream Company (“Altus”) and its subsidiary Altus Midstream LP (“Altus LP”), under which the Partnership and Altus will combine their businesses in an all-stock transaction (the “Transaction”). On February 22, 2022, the Partnership closed the Transaction and in exchange for all of the equity interests of the Partnership and General Partner, Raptor Holdco received 50,000,000 shares of Altus’ Class C common stock and 50,000,000 common units of Altus LP. Upon the completion of the Transaction, the Partnership’s unitholders own approximately 75.5% of the new combined entity and Altus’ stockholders own approximately 24.5%.

Altus is the legal acquiror of the Partnership because Altus is issuing their shares to effectuate the Transaction. However, for accounting purposes, the Transaction will be treated as a reverse merger and accounted for using the acquisition method in accordance with ASC 805, Business Combinations. As such, Altus will be treated as the “acquired” company for accounting purposes. This determination is primarily based on the fact that upon consummation of the Transaction, the Partnership unitholders have a majority of the voting power of the combined company, the Partnership controls a majority of the governing body of the combined company, and the Partnership’s senior management comprises the majority of the senior management of the combined company.

Accordingly, for financial reporting purposes, the net assets of the Partnership will be stated at historical carrying values and its consolidated financial statements will be presented as the predecessor to the combined company in the historical financial statements following the consummation of the Transaction, with one adjustment, which is to retroactively adjust the accounting acquirer’s legal capital to reflect the legal capital of the accounting acquiree. Furthermore, for accounting purposes, the assets and liabilities of Altus will be recorded at their fair values measured as of the acquisition date, with any excess purchase price over the fair value of the net assets acquired, if any, to be recorded as goodwill. The results of Altus will be presented within the consolidated results of the Partnership from the date of acquisition going forward. The initial allocation of the purchase price is still being assessed by the Partnership.

Immediately following the close of the Transaction, all outstanding Class A-1 and Class A-2 Units were exchanged for 2,650,000 shares of Class A common stock (“Class A Shares”) of Altus. These Class A Shares were distributed pro rata to all holders of Class A-1 and Class A-2 Units pro rata and will primarily vest over three to four years contingent upon continuous employment. Similarly, the Class A-3 Units were exchanged for approximately 163,000 Class A Shares and will vest over four years contingent upon continuous employment. This change represents a type IV modification to the unvested Class A Units, which establishes a new measurement date.

Key Performance Metrics

Adjusted EBITDA

Adjusted EBITDA is defined as net income (loss) adjusted for interest, taxes, depreciation and amortization, impairment charges, asset write-offs, the proportionate EBITDA from our equity method investment, equity in earnings (losses) from investments recorded using the equity method, stock-based compensation expense, extraordinary losses and unusual or non-recurring charges. Adjusted EBITDA provides a basis for comparison of our business operations between current, past and future periods by excluding items that we do not believe are indicative of our core operating performance. Adjusted EBITDA is $415.7 million, $221.1 million and $202.2 million for the years ended December 31, 2021, 2020 and 2019, respectively. Adjusted EBITDA is a non-GAAP measure. Refer to the “Non-GAAP Measures” section below for further discussion.

Segment Adjusted EBITDA

Segment Adjusted EBITDA is defined as segment net earnings or loss adjusted to exclude interest expense, income tax expense, depreciation and amortization, the proportionate effect of these same items for our equity method investments and other non-recurring items. Segment Adjusted EBITDA for the years ended December 31, 2021, 2020 and 2019 is as follows:


	Years Ended December 31,
	2021			2020			2019
	(in thousands)
Gathering and Processing	$	343,645		$	230,015		$	207,888
Transmission		82,025			(321	)		2,635
Other		(9,957	)		(9,617	)		(8,286	)
Total Segment Adjusted EBITDA		415,713			221,077			202,237

Results of Operations

Comparison of the Years Ended December 31, 2021 and 2020

The following table is a reference for the discussion that follows:


	Years Ended December 31,						Change
	2021			2020			$			%

	(dollars in thousands)
Operating revenues:
Service revenue	$	272,677		$	272,829		$	(152)			(0.1	)%
Product revenue		385,622			135,330			250,292			184.9	%
Other revenue		3,745			2,017			1,728			85.7	%

Total operating revenues		662,044			410,176			251,868			61.4	%
Operating costs and expenses:
Cost of sales (exclusive of depreciation and amortization)		233,619			65,053			168,566			259.1	%
Depreciation and amortization		243,558			223,763			19,795			8.8	%
Operating expenses		90,894			93,704			(2,810	)		(3.0	)%
General and administrative expenses		28,588			22,917			5,671			24.7	%
Ad valorem taxes		11,512			10,985			527			4.8	%
Loss on disposal of assets		382			3,454			(3,072	)		(88.9	)%
Goodwill impairment		—			1,010,773			(1,010,773	)		(100.0	)%

Total operating costs and expenses		608,553			1,430,649			(822,096	)		(57.5	)%

Operating income (loss)		53,491			(1,020,473	)		1,073,964			(105.2	)%

Other income (expense):
Interest and other income		4,147			1,476			2,671			181.0	%
Interest expense		(117,365	)		(135,516	)		18,151			(13.4	)%
Equity in earnings (losses) of unconsolidated affiliate		63,074			(308	)		63,382			N/M

Total other expense, net		(50,144	)		(134,348	)		84,204			(62.7	)%

Income (loss) before income taxes		3,347			(1,154,821	)		1,158,168			(100.3	)%

Income tax provision		(1,865	)		(968	)		(897	)		92.7	%

Net income (loss)	$	1,482		$	(1,155,789)		$	1,157,271			(100.1	)%

N/M—Not meaningful

Service revenue

Service revenue consists of service fees paid to us by our customers for providing comprehensive gathering, processing, treating and water disposal services necessary to bring natural gas, NGLs and crude oil to market. Service revenue was flat year over year. Service revenues are included entirely in the Gathering and Processing segment.

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas, and NGLs). Product revenue for the year ended December 31, 2021, increased by $250.3 million, or 184.9%, to $385.6 million, compared to $135.3 million for the year ended December 31, 2020, primarily due to period over period increases in commodity prices. For the year ended December 31, 2021 versus the same period in 2020, natural gas residue prices increased $3.06 per MMBtu or over 290%, NGL prices increased $23.87 per barrel or over 190% and condensate prices increased $15.07 per barrel or over 45%. Similarly over the same period, natural gas residue volumes increased 11.8 million MMBtu or 9%, NGL volumes decreased 4.7 million barrels or 18% and condensate volumes increased 1.7 million barrels or 64%. Product revenues are included entirely in the Gathering and Processing segment.

Other revenue

Other revenue consists of the amortization of contract liabilities related to capital reimbursements received from our customers. Other revenue for the year ended December 31, 2021, increased by $1.7 million, or 85.7%, to $3.7 million, compared to $2.0 million for the year ended December 31, 2020, primarily due to new capital reimbursements received resulting in increased amortization. Other revenues are included entirely in the Gathering and Processing segment.

Cost of sales (exclusive of depreciation and amortization)

Cost of sales (exclusive of depreciation and amortization) primarily consists of purchases of NGLs and natural gas from our producers at contracted market prices to support product sales to other third parties. Cost of sales for the year ended December 31, 2021, increased $168.5 million or 259.1%, to $233.6 million, compared to $65.1 million for the year ended December 31, 2020, primarily due to the period over period increase in commodity prices. Cost of sales (exclusive of depreciation and amortization) are included entirely in the Gathering and Processing segment.

Depreciation and amortization

Depreciation and amortization consists of depreciation expense on property, plant and equipment and amortization expense for intangible assets. Depreciation and amortization for the year ended December 31, 2021, increased $19.8 million, or 8.8%, to $243.6 million, compared to $223.8 million for the year ended December 31, 2020, primarily due to an increase in our depreciable asset base from projects placed into service over the past year.

Operating expenses

Operating expenses consist of equipment rental fees, labor, outside services, and lubricants and chemicals all incurred in the operation of our assets. Operating expenses for the year ended December 31, 2021, decreased $2.8 million, or 3.0%, to $90.9 million, compared to $93.7 million for the year ended December 31, 2020, primarily due to decreased electricity costs associated with electricity credits received from one of our primary electricity providers during the month of February.

General and administrative expenses

General and administrative expenses consist of day-to-day costs we incur to administer our business including administrative labor, insurance costs and legal fees. General and administrative expenses for the year ended December 31, 2021, increased $5.7 million, or 24.7%, to $28.6 million, compared to $22.9 million for the year ended December 31, 2020, primarily due to $5.7 million of transactions costs incurred for the Altus merger during the current year.

Ad valorem taxes

Ad valorem taxes for the year ended December 31, 2021, increased $0.5 million, or 4.8%, to $11.5 million, compared to $11.0 million for the year ended December 31, 2020, primarily due to the aforementioned increase to our fixed asset base and its increased utilization.

Loss on disposal of assets

Loss on disposal of assets consists of the losses associated with the dispositions of fixed assets. Loss on disposal of assets for the year ended December 31, 2021, decreased $3.1 million, or 88.9%, to $0.4 million, compared to $3.5 million for the year ended December 31, 2020, primarily due to the write-off of a compressor during the year ended December 31, 2020.

Goodwill impairment

Interest and other income

Interest and other income consists of miscellaneous, non-operational interest and income or expense activities entered into by the Partnership. Interest and other income for the year ended December 31, 2021, increased $2.6 million, to income of $4.1 million, compared to income of $1.5 million during the year ended December 31, 2020, primarily due to a $2.5 million settlement from the former owners of one of our subsidiaries, CR Permian Holdings, LLC, that was acquired in November of 2018.

Interest expense

Interest expense includes mainly the interest incurred on our outstanding indebtedness and associated interest rate swaps, as well as amortization of deferred financing costs, mainly debt origination and commitment fees. Interest expense for the year ended December 31, 2021, decreased $18.1 million, or 13.4%, to $117.4 million, compared to $135.5 million for the year ended December 31, 2020, primarily due to lower settlements and fair value marks on our interest rate swaps totaling $23.4 million. Also, interest expense on our outstanding term loans decreased $10.9 million due to a period over period decrease in the floating rates of the associated debt. Partially offsetting these decreases was a decrease in capitalized interest of $15.3 million, primarily associated with ceasing interest capitalization on our equity investment in PHP after the associated pipeline went into service in January of 2021.

Equity in earnings (losses) of unconsolidated affiliate

Equity in earnings (losses) of unconsolidated affiliate consists of the earnings associated with the investment in PHP. Equity in earnings of unconsolidated affiliate for the year ended December 31, 2021, increased $63.4 million, to $63.1 million, as compared to $0.3 million equity in losses for the year ended December 31, 2020, primarily due to the PHP pipeline going into service during January of 2021.

Income tax provision

Our provision for income taxes is solely attributable to Texas state margin tax and the associated deferred income taxes which result from differences between the carrying amount and tax bases related to property, plant and equipment and intangible assets. Income tax provision for the year ended December 31, 2021, increased $0.9 million, to $1.9 million, compared to $1.0 million for the year ended December 31, 2020. Income tax provision as a percentage of revenue was 0.3% during the year ended December 31, 2021 and 0.2% during the year ended December 31, 2020.

Comparison of the Years Ended December 31, 2020 and 2019

The following table is a reference for the discussion that follows:


	Years Ended December 31,				Change
	2020		2019		$			%

	(dollars in thousands)
Operating revenues:
Service revenue	$	272,829	$	233,987	$	38,842			16.6	%
Product revenue		135,330		144,270		(8,940	)		(6.2	)%
Other revenue		2,017		487		1,530			N/M

Total operating revenues		410,176		378,744		31,432			8.3	%
Operating costs and expenses:
Cost of sales (exclusive of depreciation and amortization)		65,053		70,272		(5,219	)		(7.4	)%
Depreciation and amortization		223,763		202,664		21,099			10.4	%
Operating expenses		93,704		85,537		8,167			9.5	%
General and administrative expenses		22,917		22,601		316			1.4	%
Ad valorem taxes		10,985		8,172		2,813			34.4	%


	Years Ended December 31,						Change
	2020			2019			$			%

	(dollars in thousands)
Loss on disposal of assets		3,454			1,573			1,881			119.6	%
Goodwill impairment		1,010,773			—			1,010,773			100.0	%

Total operating costs and expenses		1,430,649			390,819			1,039,830			266.1	%

Operating loss		(1,020,473	)		(12,075	)		(1,008,398	)		N/M

Other income (expense):
Interest and other income		1,476			1,736			(260	)		N/M
Interest expense		(135,516	)		(133,535	)		(1,981	)		1.5	%
Gain on sales of interests of unconsolidated affiliate		—			3,362			(3,362	)		(100.0	)%
Equity in earnings (losses) of unconsolidated affiliate		(308	)		440			(748	)		(170.0	)%

Total other expense, net		(134,348	)		(127,997	)		(6,351	)		5.0	%

Loss before income taxes		(1,154,821	)		(140,072	)		(1,014,749	)		N/M

Income tax provision		(968	)		(4,357	)		3,389			(77.8	)%

Net loss	$	(1,155,789)		$	(144,429)		$	(1,011,360)			N/M

N/M —Not meaningful

Service revenue

Service revenue consists of service fees paid to us by our customers for providing comprehensive gathering, treating, processing and water disposal services necessary to bring natural gas, NGLs and crude oil to market. Service revenue for the year ended December 31, 2020, increased by 38.8 million, or 16.6%, to $272.8 million, compared to $234.0 million for the year ended December 31, 2019, primarily due to a period over period increase in gathered gas volumes of 179.2 Mcf per day and processed gas volumes of 140.2 Mcf per day. Service revenues are included entirely in the Gathering and Processing segment.

Product revenue

Product revenue consists of commodity sales (including condensate, natural gas, and NGLs). Product revenue for the year ended December 31, 2020, decreased by $9.0 million, or 6.2%, to $135.3 million, compared to $144.3 million for the year ended December 31, 2019, primarily due to period over period decreases in NGL prices of $2.52 per barrel or 17% and condensate prices of $11.54 per barrel or 25%. Partially offsetting these increases was a period over period increase in natural gas prices of $0.21 per MMBtu or 28% and an increase in overall product volumes sold related to the portion of the aforementioned increase of our processed gas volumes where we act as the principal on the sale at the plant tailgate. During the year ended December 31, 2020, natural gas residue volumes increased 31.6 million MMBtu or 33%, NGL volumes increased 210.7 thousand barrels or 1% and condensate volumes increased 387.5 thousand barrels or 21%. Product revenues are included entirely in the Gathering and Processing segment.

Other revenue

Other revenue consists of the amortization of contract liabilities related to capital reimbursements received from our customers. Other revenue for the year ended December 31, 2020, increased by $1.5 million to $2.0 million, compared to $0.5 million for the year ended December 31, 2019, primarily due to new contract liabilities and their associated amortization. Other revenues are included entirely in the Gathering and Processing segment.

Cost of sales (exclusive of depreciation and amortization)

Cost of sales (exclusive of depreciation and amortization) primarily consists of purchases of NGLs from our producers at contracted market prices to support product sales to other third parties. Cost of sales (exclusive of depreciation and amortization) for the year ended December 31, 2020, decreased $5.2 million or 7.4%, to $65.1 million, compared to $70.3 million for the year ended December 31, 2019, primarily due to the period over period decrease in NGL prices. Cost of sales (exclusive of depreciation and amortization) are included entirely in the Gathering and Processing segment.

Depreciation and amortization

Depreciation and amortization consists of depreciation expense on property, plant and equipment and amortization expense for intangible assets. Depreciation and amortization for the year ended December 31, 2020, decreased $21.1 million, or 10.4%, to $223.8 million, compared to $202.7 million for the year ended December 31, 2019, primarily due to the acquisition of the Permian Gas assets in June of 2019 and the overall increase in our depreciable asset base due to projects placed into service over the past year.

Operating expenses

Operating expenses consist of equipment rental fees, labor, outside services, and lubricants and chemicals all incurred in the operation of our assets. Operating expenses for the year ended December 31, 2020, increased $8.2 million, or 9.6%, to $93.7 million, compared to $85.5 million for the year ended December 31, 2019, primarily due to increased equipment rental fees associated with increased compression needs related to the increase in volumes on our gathering systems.

Ad valorem taxes

Ad valorem taxes for the year ended December 31, 2020, increased $2.8 million, or 34.4%, to $11.0 million, compared to $8.2 million for the year ended December 31, 2019, primarily due to the aforementioned increase to our fixed asset base and its increased utilization, including the Permian Gas acquisition.

Loss on disposal of assets

Loss on disposal of assets consists of the loss associated with the disposition of a fixed asset. Loss on disposal of assets for the year ended December 31, 2020, increased $1.9 million, or 119.6%, to $3.5 million, compared to $1.6 million for the year ended December 31, 2019, primarily due to the write-off of a compressor during the year ended December 31, 2020.

Goodwill impairment

Goodwill impairment represents the charge to earnings and is calculated as the amount by which a reporting unit’s carrying value exceeds its fair value, determined during a goodwill impairment test. Goodwill impairment increased $1.0 billion due to the goodwill impairment for the year ended December 31, 2020 and no impairment taken during the year ended December 31, 2019. During the first four months of 2020, current and forward commodity prices significantly declined from their levels at December 31, 2019 due primarily to the decreases in energy demand as a result of the outbreak of the COVID-19 pandemic and actions taken by OPEC+ relating to the oversupply of oil. Based on our quantitative assessments, we determined that all goodwill at all reporting units should be fully impaired, and accordingly recorded a $1.0 billion impairment for the year ended December 31, 2020.

Gain on sales of interest in unconsolidated affiliate

Gain on sale of interest in unconsolidated affiliate for the year ended December 31, 2020, decreased $3.4 million to $0 due to no gain being recognized during the year ended December 31, 2020. The gain of $3.4 million recorded during the year ended December 31, 2019 related to the sale of 23.3% of our interests held in PHP to two different third parties that exercised purchase options that were provided through PHP’s LLC agreement.

Income tax provision

Our provision for income taxes consists primarily of the Texas state margin tax and the associated deferred income taxes which result from differences between the carrying amount and tax bases related to property, plant and equipment and intangible assets. Income tax provision for the year ended December 31, 2020, decreased $3.4 million, to $1.0 million, compared to $4.4 million for the year ended December 31, 2019. Income tax provision as a percentage of revenue was 0.2% during the year ended December 31, 2020 and 1.2% during the year ended December 31, 2019.

Non-GAAP Measures

In addition to net income (loss), which is a measure presented in accordance with U.S. GAAP, management believes that Adjusted EBITDA provides relevant and useful information to management and investors to assess our performance. Adjusted EBITDA is a supplemental measure of BCP’s performance that is neither required by nor presented in accordance with U.S. GAAP. This measure is limited in its usefulness and should not be considered a substitute for U.S. GAAP metrics such as income (loss) from operations, net income (loss), or any other performance measures derived in accordance with U.S. GAAP and may not be comparable to similar measures used by other companies.

Adjusted EBITDA represents net income (loss) adjusted for interest, taxes, depreciation and amortization, impairment charges, asset write-offs, the proportionate EBITDA from our equity method investment, equity in earnings (losses) from investments recorded using the equity method, stock-based compensation expense, extraordinary losses and unusual or non-recurring charges.

We believe that Adjusted EBITDA provides a meaningful understanding of certain aspects of earnings (loss) before the impact of investing and financing charges and income taxes. Adjusted EBITDA is useful to an investor in evaluating our performance because this measure:

•

Is widely used by analysts, investors and competitors to measure a company’s operating performance;

•

Is a financial measurement that is used by rating agencies, lenders, and other parties to evaluate our credit worthiness; and

•

Is used by our management for various purposes, including as a measure of performance and as a basis for strategic planning and forecasting.

The reconciliations of net income (loss) to Adjusted EBITDA for the years ended December 31, 2021, 2020 and 2019 are as follows:


	Years Ended December 31,
	2021			2020			2019

	(in thousands)
Net Income (loss)	$	1,482		$	(1,155,789	)	$	(144,429	)
Add back:
Interest expense		117,365			135,516			133,535
Provision for income taxes		1,865			968			4,357
Depreciation and amortization		243,558			223,763			202,664
Contract asset amortization		1,792			1,805			1,185
Proportionate equity method investments EBITDA		83,593			1,150			17
Stock-based compensation		—			—			3,809
Goodwill impairment		—			1,010,773			—
Loss on disposal of assets		382			3,454			1,573
Derivative loss due to Winter Storm Uri		13,456			—			—
Producer settlement		6,827			—			—
Altus merger transaction costs		5,730			—			—
Other one-time costs/expenses		2,856			—			—
Losses from equity method investments		—			308			—
Deduct:
Interest income		(115	)		(3	)		(34	)
Earnings from equity method investments		(63,074	)		—			(440	)
Gain on debt extinguishment		(4	)		(868	)		—

Adjusted EBITDA	$	415,713		$	221,077		$	202,237

Liquidity and Capital Resources

The Partnership’s primary use of capital since inception has been for the initial construction of gathering and processing assets. For 2021, the Partnership’s primary capital spending requirements are related to expanding our gathering system to service new wells as they come on-line and for facility improvements.

The Partnership believes that cash on hand, cash flow from operations and borrowings under its credit facilities will be sufficient to fund its planned capital expenditures and operating expenses over the next twelve months. To date, the funds received from previous partners’ capital contributions, as well as the Partnership’s ability to obtain lending commitments, have provided the liquidity necessary for the Partnership to fund its operations. If the Partnership is unable to generate positive operating cash flows, additional debt and equity financings may be necessary to sustain future operations.

Given the crude oil price collapse on lower demand and economic activity resulting from the COVID-19 pandemic and related governmental actions during 2020, the Partnership continues to monitor expected natural gas throughput volumes. Throughout the year ended December 31, 2021, the Partnership has realized increases in throughput volumes and increases in commodity values as a result of higher demand and improving economic conditions. We expect this trend to continue throughout 2022. BCP’s results, including projections related to capital resources and liquidity, could be materially affected by the continuing COVID-19 pandemic.

Capital Requirements

During the years ended December 31, 2021, 2020 and 2019, capital spending for midstream infrastructure assets totaled $82.7 million, $199.1 million and $457.0 million, respectively. Management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service all of our third-party customers.

Additionally, during the years ended December 31, 2021, 2020 and 2019, the Partnership made cash contributions totaling $20.5 million, $306.5 million and $348.9 million, respectively, for the 26.67% interest ownership in PHP. Contributions for the year ended December 31, 2019 were partially offset by proceeds of $92.7 million associated with the sale of 23.3% of our interests in PHP to two third parties.

The Partnership anticipates its existing capital resources will be sufficient to fund the Partnership’s future capital expenditures for PHP and the Partnership’s existing infrastructure assets. For further information on the PHP equity method investment, refer to Note 7, Investment in Unconsolidated Affiliate, to our consolidated financial statements appearing in Exhibit 99.4 to this Form 8-K.

Distributions

During March 2021, the Partnership borrowed the additional $30.2 million associated with the conversion date term commitment for the $513 million term loan as all conditions of the term conversion were met. The Partnership subsequently distributed the full borrowing to our equity sponsors. During November 2021, an additional $21.0 million was distributed to equity sponsors utilizing cash on hand.

Cash Flows

The following tables present cash flows from operating, investing, and financing activities during the periods presented:


	Years Ended December 31,
	2021			2020			2019

	(in thousands)
Net cash flows from operating activities	$	235,569		$	102,096		$	44,658
Net cash flows from investing activities		(99,621	)		(505,586	)		(713,239	)
Net cash flows from financing activities		(136,810	)		372,774			627,566

Net change in cash	$	(862	)	$	(30,716	)	$	(41,015	)

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and equity in earnings (losses) from unconsolidated affiliate. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of products, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period:

Year Ended December 31, 2021

Operating activities provided $235.6 million of cash, resulting from our net income of $1.5 million distributions from our unconsolidated affiliate of $68.3 million, non-cash charges of $209.7 million offset by $19.4 million in derivative settlements and net cash used in changes in our operating assets and liabilities of $24.5 million. Non-cash charges of $209.7 million consist primarily of depreciation and amortization of $243.6 million, $12.5 million derivative fair value adjustments, $13.4 million amortization of deferred financing costs, $1.8 million amortization of contract costs and $1.9 million in deferred income taxes partially offset by $63.1 million in equity in earnings of unconsolidated affiliate. Net cash used in changes in our operating assets and liabilities consisted primarily of a $88.5 million increase in accounts receivable, a $11.5 million increase in other assets, a $2.7 million decrease in accounts payable, offset by an increase in accrued liabilities of $77.4 million and a decrease of $0.8 million in net operating lease activity.

Year Ended December 31, 2020

Operating activities provided $102.1 million of cash, resulting from our net loss of $1.2 billion, $7.8 million of derivative settlements net cash used in changes in our operating assets and liabilities of $1.1 million, offset by non-cash charges of $1.3 billion. Non-cash charges of $1.3 billion consist primarily of a $1.0 billion goodwill impairment, depreciation and amortization of $223.8 million, $17.3 million derivative fair value adjustments and $11.9 million amortization of deferred financing costs. Net cash used in changes in our operating assets and liabilities consisted primarily of a $7.3 million increase in accounts receivable, a $6.6 million increase in other assets and an increase of $0.7 million in net operating lease activity, offset by an increase in accounts payable of $4.2 million, and increase in accrued liabilities of $9.2 million.

Year Ended December 31, 2019

Operating activities provided $44.7 million of cash, resulting from our net loss of $144.4 million, net cash used in changes in our operating assets and liabilities of $23.9 million, offset by $1.5 million of derivative settlements and net non-cash charges of $211.5 million. Non-cash charges of $211.5 million consist primarily of depreciation and amortization of $202.7 million, amortization of deferred financing costs of $9.7 million, stock-based compensation of $3.8 million and deferred taxes of $4.4 million, partially offset by a contingent liability remeasurement of $8.1 million. Net cash used in changes in our operating assets and liabilities consisted primarily of a $27.3 million increase in accounts receivable and an increase in other assets of $14.3 million, partially offset by a $17.8 million increase in accrued liabilities.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, and cash distributions from and investments in our unconsolidated affiliate. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Following is a summary of investing activities by period:

Year Ended December 31, 2021

Investing activities used $99.6 million of cash, resulting from purchases of property and equipment of $78.0 million, intangible asset expenditures of $4.7 million and investments in our unconsolidated affiliate of $20.5 million partially offset by proceeds from disposal of assets of $3.6 million.

Year Ended December 31, 2020

Investing activities used $505.6 million of cash, resulting from purchases of property and equipment of $181.4 million, intangible asset expenditures of $17.6 million and investments in our unconsolidated affiliate of $306.5 million.

Year Ended December 31, 2019

Investing activities used $713.2 million of cash, resulting from purchases of property and equipment of $329.3 million, intangible asset expenditures of $27.7 million, investments in our unconsolidated affiliate of $348.9 million and acquisition from third parties, net of cash received of $100.0 million partially offset by proceeds from sales of interests in our unconsolidated affiliate of $92.7 million.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings, which are primarily used to fund our acquisitions and growth capital expenditures and equity contributions from or distributions to our partners.

Following is a summary of financing activities by period:

Year Ended December 31, 2021

Financing activities used $136.8 million of cash, resulting from principal payments on debt of $166.0 million and partner distributions of $51.2 million, partially offset by proceeds from issuance of debt obligations, net of issuance costs of $65.5 million and partner contributions of $14.9 million.

Year Ended December 31, 2020

Financing activities provided $372.8 million of cash, resulting from proceeds from issuance of debt obligations, net of issuance costs of $375.0 million, and equity contributions of $280.9 million, net of repayments of debt of $203.9 million and consideration payable from acquisition of $79.3 million.

Year Ended December 31, 2019

Financing activities provided $627.6 million of cash, resulting from proceeds from issuance of debt obligations, net of issuance costs of $519.8 million, equity contributions of $586.8 million, net of repayments of debt of $180.7 million, payments of contingent liability of $9.1 million and equity distributions of $289.3 million.

Financing Arrangements

See Note 10, Long Term Debt, and Note 11, Equity, respectively, to our consolidated financial statements appearing in Exhibit 99.4 to this Form 8-K for a discussion of debt and equity financing arrangements for the Partnership.

Contractual Obligations

Long term debt obligation and related interest payments – We have contractual obligations for principal and interest payments on our senior notes. See Note 10, Long Term Debt, to our consolidated financial statements appearing in Exhibit 99.4 to this Form 8-K for additional information.

Operating lease commitments – We have contractual obligations for operating leases on certain real estate and equipment. See Note 9, Leases, to our consolidated financial statements appearing in Exhibit 99.4 to this Form 8-K for additional information.

Under certain of our transportation services agreements with third party pipelines to transport natural gas and NGLs with current contract terms from 2021-2031, if we fail to ship a minimum throughput volume during any year, then we will pay a deficiency payment for transportation based on the volume shortfall up to the MVC amount. The partnership has made no historical shortfall payments through December 31, 2021.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements, as defined by applicable rules and regulations of the SEC, that are reasonably likely to have a current or future material effect on our financial condition, results of operations, liquidity, capital expenditures or capital resources.

Critical Accounting Policies

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We evaluate our significant estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates under different assumptions or conditions, impacting our reported results of operations and financial condition.

We believe that the accounting policies described below involve a significant degree of judgment and complexity and have the greatest potential effect on our consolidated financial statements. Accordingly, we believe these are the most critical to aid in fully understanding and evaluating our consolidated financial condition and results of operations. For further information, see Note 2, Summary of Significant Accounting Policies, to our consolidated financial statements included in Exhibit 99.4 to this Form 8-K.

Revenue Recognition

We provide gathering, processing, and disposal services and we sell commodities (including condensate, NGLs and natural gas) under various contracts.

We recognize revenues for services and products under revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. These contracts include:

Fee-based arrangements—Under fee-based contract arrangements, the Partnership provides gathering, processing and disposal services to producers and earns a net margin based on volumes. While transactions vary in form, the essential element of each transaction is the use of the Partnership’s assets to transport a product or provide a processed product to an end-user at the tailgate of the plant or pipeline. This revenue stream is generally directly related to the volume of water, natural gas, crude oil, NGLs, and condensate that flows through the Partnership’s systems and facilities and is not normally dependent on commodity prices. The Partnership primarily acts as an agent under these contracts selling the underlying commodities on behalf of the producer and remitting back to the producer the net proceeds. These such sales and remitted proceeds are presented net within revenue. However, in certain instances the Partnership acts as the principal for processed NGLs by purchasing them from the associated producer at the tailgate of the plant at index prices. This purchase and the associated 3rd party sale are presented gross within revenues and cost of sales.

Percent-of-proceeds arrangements—Under percentage-of-proceeds based contract arrangements, the Partnership will gather and process natural gas on behalf of producers and sell the outputs, including residue gas, NGLs and condensate at market prices. The Partnership remits an agreed-upon percentage of proceeds to the producer based on the market price received from 3rd parties or the index price defined in the contract. Under these arrangements, revenue is recognized net of the agreed-upon proceeds remitted to producers when the Partnership acts as an agent of the producer for the associated 3rd party sale. However, in certain instances the Partnership acts as the principal for processed residue and NGLs by purchasing these volumes from the associated producer at the tailgate of the plant at index prices. This purchase and the associated 3rd party sale are presented gross within revenues and cost of sales.

Percent-of-products arrangements—Under percent-of-products based contract arrangements, the Partnership will gather and process natural gas on behalf of producers. As partial compensation for services, the producer assigns to the Partnership, for no additional consideration, all right, title and interest to a set percentage, as defined in the contract, of the processed residue volumes. The Partnership recognizes the fair value of these products as revenue when the associated performance obligation has been met.

Product sales contracts—Under these contracts, we sell natural gas, NGLs or condensate to third parties. These sales are presented gross within revenues and cost of sales or net within revenues depending on whether the Partnership acts as the agent or the principal in the sale transaction as discussed above.

Our fee-based service contracts primarily have a single performance obligation to deliver a series of distinct goods or services that are substantially the same and have the same pattern of transfer to our producers. For performance obligations associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of products delivered/sold or services performed, because the single performance obligation is satisfied over time using the same performance measure of progress toward satisfaction of the performance obligation. The transaction price under our fee-based service contracts includes variable consideration that varies primarily based on actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to transfer the services and/or products under the contracts, we allocate the variable consideration entirely to the distinct service utilizing the allocation exception guidance under Topic 606, and accordingly recognize the variable consideration as revenues at the time the good or service is transferred to the producer.

We recognize revenues at a point in time for performance obligations associated with percent-of-proceeds contract elements, percent-of-products contract elements and product sale contracts, and these revenues are recognized because control of the underlying product is transferred to the customer or producer when the distinct good is provided to the customer or producer.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our producers or customers. Actual results can vary from those judgments and assumptions.

Minimum Volume Commitments—The Partnership has certain agreements that provide for quarterly or annual minimum volume commitments (MVCs). Under these MVCs, our producers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A producer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. None of the Partnership’s MVC provisions allow for producers to make up past deficient volumes in a future period. However, certain MVC provisions allow producers to carryforward volumes delivered in excess of a current period MVC to future periods. The Partnership recognizes revenue associated with MVCs when a counterparty has not met the contractual MVC at the completion of the contracted measurement period or we determine that the counterparty cannot meet the contractual MVC by the end of the contracted measurement period. For the years ended December 31, 2021, 2020 and 2019 the Partnership recognized revenues from minimum MVCs of $2.5 million, $0.1 million and $1.8 million, respectively.

Fair Value Measurements

Fair value accounting is applied for all assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Fair value is defined as the exchange price that would be received for an asset or an exit price that would be paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Partnership follows the established framework for measuring fair value and expands disclosures about fair value measurements.

Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to measurements involving significant unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are as follows:

•

Level 1—Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at the measurement date.

•

Level 2—Inputs are observable, unadjusted quoted prices in active markets for similar assets or liabilities, unadjusted quoted prices for identical or similar assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the related assets or liabilities.

•

Level 3—Unobservable inputs are used when little or no market data is available. The fair value hierarchy gives the lowest priority to level 3 inputs.

The level in the fair value hierarchy within which a fair value measurement in its entirety falls is based on the lowest-level input that is significant to the fair value measurement in its entirety.

The Partnership’s consolidated financial instruments consist of accounts receivable, accounts payable and accrued expenses and are stated at their carrying value, which approximates fair value due to the short time to the expected receipt or payment date. The consolidated financial statements also include fair value level 2 measurements of commodity swaps and interest rate derivatives.

Impairment of Long-Lived Assets

In accordance with FASB ASC Topic 360, Property, Plant and Equipment, long-lived assets, excluding goodwill, to be held and used by the Partnership are reviewed to determine whether any events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, the Partnership bases their evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present.

In performing this review, an undiscounted cash flow test is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.

Recently Issued and Adopted Accounting Pronouncements

See Note 2, Summary of Significant Accounting Policies, to our consolidated financial statements appearing in Exhibit 99.4 to this Form 8-K for a discussion of accounting pronouncements recently adopted and recently issued accounting pronouncements not yet adopted and their potential impact to our consolidated financial statements.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market and other risks, including the effects of changes in interest rates and inflation, as well as risks to the availability of funding sources, hazard events, and specific asset risks.

Interest Rate Risk

The market risk inherent in our financial instruments and our financial position represents the potential loss arising from adverse changes in interest rates. As of December 31, 2021, we have interest bearing debt with a principal amount of $2.3 billion, respectively.

Our $1.25 billion term loan as of December 31, 2021 is a variable rate loan that accrues interest periodically at a rate equal to 4.25% plus LIBOR subject to a floor of 1%. Average 1 month USD LIBOR subject to the 1% floor was 1.000%, 1.171% and 2.321% for the years ended December 31, 2021, 2020 and 2019, respectively.

Our $100 million revolving line of credit as of December 31, 2021 is a variable rate loan that accrues interest periodically at a rate equal to LIBOR plus the applicable margin based on our consolidated total leverage ratio, which is between 3.75% and 4.00%.

Our $690 million term loan as of December 31, 2021 is a variable rate loan that accrues interest periodically rate equal to 4.75% plus LIBOR. Average 1 month USD LIBOR was 0.103%, 0.629% and 2.299% for the years ended December 31, 2021, 2020 and 2019, respectively.

Our $60 million revolving line of credit as of December 31, 2021 is a variable rate loan that accrues interest periodically a rate equal to LIBOR plus the applicable margin based on our consolidated total leverage ratio, which is between 4.25% and 4.75%.

Our $513 million term loan as of December 31, 2021 is a variable rate loan that accrues interest periodically rate equal to 1.625% plus adjusted LIBOR (subject to a 1% floor) for four years after the closing date and at a rate equal to 1.875% plus adjusted LIBOR (subject to a 1% floor) thereafter.

Based upon our interest rates as of December 31, 2021, a one percent (1%) increase subject to the floor in interest rates in our variable rate indebtedness would result in approximately $1.4 million in additional annual interest expense for the year ended December 31, 2021.