USA Compression Partners LP : 2021 UBS Winter Infrastructure & Energy Virtual Conference Presentation

USA Compression Partners, LP

2021 UBS Winter Infrastructure &

Energy Virtual Conference

January 12-13, 2021

Disclaimer

This presentation contains forward-looking statements relating to the operations of USA Compression Partners, LP (the "Partnership") that are based on management's current expectations, estimates and projections about its operations. You can identify many of these forward-looking statements by words such as "believe," "expect," "intend," "project," "anticipate," "estimate," "continue," "if," "outlook," "will," "could," "should," or similar words or the negatives thereof. You should consider these statements carefully because they discuss our plans, targets, strategies, prospects and expectations concerning our business, operating results, financial condition, our ability to make distributions and other similar matters. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. These include risks relating to changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries specifically, changes in the long-term supply of and demand for natural gas and crude oil, actions taken by our customers, competitors and third-party operators, our ability to realize the anticipated benefits of acquisitions, competitive conditions in our industry, the severity and duration of world health events and the factors set forth under the heading "Risk Factors" or included elsewhere that are incorporated by reference herein from our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission, and if applicable, our Quarterly Reports on Form 10-Q and our Current Reports on Form 8-K. As a result of such risks and others, our business, financial condition and results of operations could differ materially from what is expressed or forecasted in such forward-looking statements. Before you invest in our common units, you should be aware of such risks, and you should not place undue reliance on these forward-looking statements. Any forward-looking statement made by us in this presentation speaks only as of the date of this presentation. Unpredictable or unknown factors not discussed herein could also have material adverse effects on forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Important Note Regarding Non-Predecessor Information

On April 2, 2018, the Partnership consummated the acquisition of CDM Resource Management LLC and CDM Environmental & Technical Services LLC, which together represent the CDM Compression Business (the "USA Compression Predecessor"), from Energy Transfer, and other related transactions (collectively, the "Transactions"). Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. Therefore, the historical consolidated financial statements of the Partnership are comprised of the balance sheet and statement of operations of the USA Compression Predecessor as of and for periods prior to April 2, 2018. The historical consolidated financial statements of the Partnership are also comprised of the consolidated balance sheet and statement of operations of the Partnership, which includes the USA Compression Predecessor, as of and for all periods subsequent to April 2, 2018. The information shown in this presentation under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership for financial reporting purposes, for periods prior to the Transactions and is presented for illustrative purposes only. Such information does not reflect the Partnership's historical results of operations and is not indicative of the results of operations of the Partnership's predecessor, the USA Compression Predecessor, for such periods.

USAC Overview

USAC Overview

Large Horsepower Strategy Critical for Domestic Natural Gas Infrastructure

Business Snapshot

USAC Market Statistics

• ■ USAC provides compression services across a geographically-diversified operating area

• ■ 22+ year history with primary focus on large horsepower (1,000 HP+) applications

• ■ "Southwest Airlines" standardized business model

• ■ Focus areas: Permian/Delaware; Marcellus/Utica; Mid-Continent/SCOOP/STACK; S. Texas; E. Texas; Louisiana; Rockies

• ■ Active Fleet: 3.0mm Horsepower - >70% is greater than 1,000 HP

• ■ Average Utilization ~84%

• ■ ~750 employees

Note: Market data as of January 8, 2021. Financial and operational data as of September 30, 2020.

■

Public since 1/2013 (NYSE: USAC)

• ■ Current Unit Price: $13.98

• ■ Avg. Daily Trading Volume: ~250,000 units

• ■ IDRs Eliminated

($ in billions)
LP Equity Value	$1.4 billion
Preferred Equity	0.5 billion
ABL	0.5 billion
Sr. Notes	1.5 billon
Total Long-Term Debt	2.0 billion
Enterprise Value	$3.8 billion

Q3 2020 Recap

Stability Nearing Year-End

2020 Guidance

■	Q3 2020 fleet HP of 3.7 million / average revenue generating HP of 3.0 million
■	Q3 2020 average horsepower utilization of 84%
Operational
■	Quote activity picking up
Update
■	~11,000 large HP delivered in Q3 2020
■	Q4 Capex: 7,500 HP (3 units) left for 2020 delivery
■	Q3 reflected stable results; some expected utilization degradation & pricing moderation
- Adjusted EBITDA of $104mm
Financial
- Distributable Cash Flow ("DCF") of $57mm
Update
■	Q3 adjusted gross margin percentage of 71.1%, Adjusted EBITDA margin of 64.3%
■	Common unit distribution of $0.525 for Q3; DCF coverage of 1.12x
■	Updated full-year 2020 guidance:

• - Adjusted EBITDA: $405mm - $415mm

• - DCF: $210mm - $220mm

Q3 2020 performance highlighted business stabilization; unknowns still exist

USAC Offers a Stable Infrastructure Opportunity

Natural Gas Has Proven Itself as a Long-Term Fuel; Compression is Critical!

Bullish on natural gas production & demand, both in US and globally
■
Supportive
Macro: Gas Isn't	LNG exports, petchem feedstock and power gen driving continued gas usage
■
Going Anywhere
Natural gas demand/production expected to increase through 2050 (1)
■
New vintage fleet focused on high quality CAT/Ariel machines
■
High Quality
Assets in Right	Geographic diversity, but significant density where the gas is: Permian/Delaware &
■
Places with	Northeast
Strong Customers
Strong counterparties - active customers (major oil & gas, large independent E&Ps,
■
midstream)
Providing large horsepower compression services for >20 years
Established	■
Company with
Performance throughout price cycles; no direct commodity exposure
■
History of
Stable distribution history: >$1 billion returned since IPO
Stability	■

Compression is a "must-have" part of the natural gas value chain: with increasing natural gas usage as a transition fuel to the future will come increasing requirements for compression

1. U.S. Energy Information Administration: Annual Energy Outlook 2020.

Why Focus on Midstream Compression?

Operational / Cash Flow Stability with Strong Counterparties

Wellhead (Gas & Oil)	Midstream	Downstream
Uses	Gas Lift Gas Reinjection	Regional Gathering Central Delivery Point Processing Plants	Interstate Pipelines Trunkline Gathering Gas Storage
Customer Base	Broad customer base	Typically larger operators	Typically owner-operators; Very large operators, integrated midstreams
Gas Volumes / Pressures	Lower	Medium-to-High	Higher
Compression Required	Small HP	Large-to-Extra Large	Larger-to-Extra Large (often turbines)
Stability	Dependent on commodity prices	Infrastructure-based; Longer-term	Permanent installations
Barriers to Entry/Exit	Non-existent; commodity service offering	Select group of operators; costly to install/de-mobilize	Integrated with pipeline systems

USAC's focus on midstream applications results in more stability throughout commodity price cycles

USAC Customer Overview

Top 20 Customers: Diverse Counterparties & Long-Term Relationships

Customer	% of Rev(1)	Length of relationship	Total HP	Customer	% of Rev(1)	Length of relationship	Total HP
Independent Public E&P	8%	> 10 years	292K	Large Public MLP	2%	> 10 Years	41K
Major O&G	4%	> 5 years	98K	Independent Public E&P	2%	> 10 Years	41K
Large Private E&P	4%	> 10 years	107K	Private Midstream	2%	> 5 Years	60K
Independent Public E&P	3%	< 5 Years	89K	Independent Public E&P	2%	> 10 Years	50K
Midstream Unit of Public Utility	3%	> 5 Years	145K	Independent Public E&P	2%	> 5 Years	46K
Private Midstream	3%	< 5 Years	118K	Private Midstream	1%	< 5 Years	21K
Major O&G	3%	> 10 Years	85K	Independent Public E&P	1%	< 5 Years	36K
Independent Public E&P	2%	> 5 Years	73K	Private Midstream	1%	> 5 years	59K
Private Midstream	2%	< 5 Years	72K	Private Midstream	1%	< 5 Years	41K
Private Midstream	2%	> 5 Years	72K	Independent Public E&P	1%	< 5 Years	43K
USAC #1-10	34%	1,151K	USAC #11-20	15%	439K

■ USAC standalone has historically had very little bad debt write-offs; in fact, over the last 15 years, USAC has written off only ~$2.8 million in bad debts

- Equates to 0.08% of total billings (~$3.6 billion) over same period (2)

• 1. Represents recurring revenues for the 9 months ended September 30, 2020.

• 2. Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above for USAC represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

Business Model Allows for Prudent Capital Spending…..

Historical Balance Between Capital Spending and Cash Flow Stability

• ■ Large HP focus ideally suited for growth and stability

• ■ Assets provide growth based on marketplace demands

• ■ Ability to rein in spending and operate for stable cash flow when market softens

• ■ Largely agnostic to commodity prices; tied more to overall production of (and demand for) natural gas

Total Fleet Horsepower (000s)

Post-CDMPre-CDM Acquisition Non-Predecessor (1)

Acquisition (2)

4,000 3,500 3,000 2,500 2,000 1,500 1,000

500

0

1. Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

2. Represents the results of operations of the Partnership, which includes the USA Compression Predecessor, following the Transactions.

…..Leading to Cash Flow and Asset Stability Through Cycles

UtilizationAdjusted EBITDA ($mm)HH Natural Gas

Note: YTD 2020 refers to Q1-Q3 2020.

Source: EIA.

1. Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

2. For 2018, represents the results of operations of the Partnership, which includes the results of operations of the USA Compression Predecessor for the three months ended March 31, 2018 and the results of operations of the Partnership, which includes the USA Compression Predecessor, for the nine months ended December 31, 2018.

Diversification - The "Right" Operating Regions

Dry Gas Areas Have Seen Increased Activity Lately

Note: Regional % breakdowns represent active fleet horsepower at September 30, 2020; excludes non-compression equipment.

Natural Gas: Not Going Away!

Moderating Rig Count Should Cause Near-Term Production Decreases

Slowing Rig Count / Production in Face of Resilient Demand Should Bode Well for Nat Gas

• ■ After decreasing ~75% off recent highs, total US rig count is up >20% from August lows (1)

  - After crude pullback, gas-directed rigs now represent larger proportion of total (24% vs low of 13%)

• ■ Overall gas demand destruction not as bad as initially feared by some; resilient demand has required continued production from gassy areas

• ■ Changing contribution of shale well production - rig activity will need to continue to meet expected production / demand

Domestic Rig Count (1)

US Natural Gas Withdrawals (2)

mmcf/d

1,800

1,600

1,400

1,200

1,000

800

600

400

200

125.0

115.0

105.0

95.0

85.0

75.0

0

65.0

1/7/00 12/29/02 12/20/05 12/11/08 12/3/11 11/24/14 11/15/17 11/6/20

Aug-10

Jan-12

Jun-13

Nov-14

Apr-16

Sep-17

Feb-19

Jul-20

OilGas

• 1. Source: Baker Hughes, through November 6, 2020.

• 2. Source: EIA. Data through July 2020.

Global Natural Gas Demand

Natural Gas Is Not Going Away

■ World energy usage expected to grow with growing GDP

-

Total energy usage expected to continue to grow

- Renewables growing quickly, but gas will still be critical to meet transition requirements ■ Natural gas and petroleum still expected to meet significant portion of worldwide energy needs

- By 2050, oil / natural gas are still expected to account for significant energy consumption, even with dramatic growth in renewables

World Energy Consumption 2010 - 2050E (1)

Quad Btu 300

250

200

150

100

50

0

2010

1. U.S. Energy Information Administration: Annual Energy Outlook 2019.

2015

2020	2025	2030	2035	2040	2045	2050
Liquids	Natural Gas	Coal	Nuclear	Renewables
14	© 2020 USA COMPRESSION PARTNERS, LP

Natural gas willremain a critical energy source throughout the world

Domestic Natural Gas Demand

Rising Baseload Natural Gas Demand

■ Natural gas domestic consumption was up ~3% in 2019 from 2018; 2020 expected to be down 1.7% (1)

- Longer term: Up ~15% (~11Bcf/d) since 2014 to 85 Bcf/d in 2019 (1)

- Majority of increase over time (~6.4 Bcf/d) took place in 2018

■ Largest driver has been domestic power generation sector, where natural gas surpassed coal as a fuel source in 2016 (1)

- Has significantly eroded coal's baseload share along the way

Coal vs. Gas Share of Power Generation (1)

Gas vs. Renewables Share of Power Generation (2)

60%

55%

50%

45%

40%

35%

30%

25%

20%

15%

10%

CoalGas

• 1. U.S. Energy Information Administration: Monthly Energy Review November 2020.

• 2. U.S. Energy Information Administration: Monthly Energy Review June 2020.

• 3. U.S. Energy Information Administration: Annual Energy Outlook January 2019.

60%

55%

50%

45%

40%

35%

30%

25%

20%

15%

10%

GasRenewables

Domestic Natural Gas Demand Growth

■ Natural Demand Continues to Grow…with Large Increases from…

Projected Natural Gas Demand (Bcf/d)(1)

140

120

100

80

60

40

20

0

2018ResidentialPower

2020Commercial

2030 2040 2050IndustrialTransportation

Exports - MEXExports - LNG

Exports to Mexico:

• - Growing power needs to be met by US shale gas

• - ~6 Bcf/d to Mexico by 2020

LNG Exports:

- ~7 Bcf/d by 2020; 14 Bcf/d by 2030

Power:

- ~30 Bcf/d by 2020

- Clean fuel; coal plant retirements continue

Industrial Demand:

-~35 Bcf/d by 2040

- Petrochemical plants (Gulf Coast, NE)

driving demand

Midstream infrastructure and compression needed to move natural gas through the pipeline system

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019, January 2019. 1. Converted from TCF, on a 360 day/year basis

Appendix

Organizational Chart

Note: Percentages reflect USAC unit count as of January 8, 2021.

Large Horsepower Gas Applications Drive Stability

Compression Unit Size Matters

USAC Focus:

Gas Compression Industry: Key Characteristics by Size
Small - Medium	Large	X Large	XX Large	XXX Large	Commentary
Compression Unit HP Range	0 - 400 HP	400 - 1,000 HP	1,000 - 1,500 HP	1,500 - 2,300 HP	2,300 - 5,000+ HP	More horsepower needed to move larger gas volumes
Gas Vol (MMcf/d)	0.90	3.20	5.0	8.0	13.0
Size (L x W x H, ft.)	21 x 12 x 11	33 x 19 x 16	38 x 27 x 20	43 x 34 x 20	80 x 17x 28	Increasing size, transportation & demobilization costs create significant 'barriers to exit'
Weight (lbs.)	~40,000	~85,000	~185,000	~250,000+	~400,000+
Transportation Requirements	1 F350	2 x 18-wheelers	3 x 18-wheelers	5 x 18-wheelers	8 x 18-wheelers
De-mobilization Costs (cust pays)	< $10K	~$25K	~$60K	$100K+	$200K+
Typical Contract Length	1 - 12 mos	6 months - 2 years	2 - 5 years	2 - 5 years	2 - 5 years +	Larger units = longer deployment

Note: Used CAT 3306TA ,CAT3508TALE, CAT 3516BLE, CAT 3606TALE and CAT 3608TALEas representative units for Small - Medium, Large, X Large, XX Large and XXX Large horsepowercategories, respectively. Gas volumes based on 50 psi suction pressure and 1,200 psi discharge pressure.

Balancing Distribution Stability and Leverage

Annualized Distributions per Common Unit

Stability in Distribution through the cycle

$2.50

$2.00

$1.50

USAC Historical Leverage(3)

Manageable Leverage for Stability of Business

8.0x 6.0x 4.0x 2.0x

-

Q4 2017

Q1 2018

Q2 2018

Q3 2018

Q4 2018

Q1 2019

Q2 2019

Q3 2019

Q4 2019

Q1 2020

Q2 2020

Q3 2020

• 1. Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

• 2. The USA Compression Predecessor did not pay distributions prior to the completion of the Transactions.

• 3. Historical leverage calculated as total debt divided by annualized quarterly Adjusted EBITDA for the applicable quarter, in accordance with our current Credit Agreement. Actual historical leverage may differ based on certain adjustments.

• 4. Represents the results of operations of the Partnership, which includes the USA Compression Predecessor, following the Transactions.

Operational and Financial Performance

Avg. Revenue Generating HP (000s)

Revenue ($MM)

Pre-CDM Acquisition Non-Predecessor (1)

4,000

Post-CDM Acquisition (1)(2)Pre-CDM Acquisition Non-Predecessor (1)

Post-CDM Acquisition (1)(2)

3,000

2,000

1,000

0

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 YTD 2020

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 YTD 2020

Total Capex ($MM)

Adjusted EBITDA ($MM) & Margin Percentage(3)

Pre-CDM Acquisition Non-Predecessor (1)Post-CDM Acquisition (1)(2)Pre-CDM Acquisition Non-Predecessor (1)

$500 $500

Post-CDM Acquisition (1)(2)

$400 $300 $200 $100

$0

100% 80% 60% 40% 20%

$400 $300 $200 $100

$0

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 YTD

0% 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 YTDMaintenanceOtherGrowth

2020

2020

Adjusted EBITDA (LH)Adjusted EBITDA Margin (RH)

Note: YTD 2020 refers to Q1-Q3 2020.

1. Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

2. For 2018, represents the results of operations of the Partnership, which includes the results of operations of the USA Compression Predecessor for the three months ended March 31, 2018 and the results of operations of the Partnership, which includes the USA Compression Predecessor, for the nine months ended December 31, 2018.

3. See "Basis of Presentation; Explanation of Non-GAAP Financial Measures" for information on calculations of Adjusted EBITDA and Adjusted EBITDA Margin Percentage.

Macro Thesis: The "Shift to Shale"

Shale Gas Expected to be the Primary Source in Future

■ Shale Ramp: Production from shale has now pulled even with all other sources

- 2019 est. ~ 26 Tcfe of shale / tight gas production ■ Pie Getting Bigger: EIA projecting ~43 Tcfe of total production by 2050

Natural gas production by type Tcf

50 45 40 35 30 25 20 15 10 5 0

(PSIG) 500

1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019, January 2019.

• ■ Shale gas is typically produced at lower wellhead pressures (0-50 PSIG) in contrast to conventional gas wells (100-300 PSIG)

• ■ Pipeline specifications remain constant - requiring gas pressure to be increased significantly to move gas into and through pipelines

• ■ As a result, to move the same amount of gas requires significantly more compression

Shale Production Drives Increasing Compression Requirements (1)

Unconventional

450

400

350

300

250

200

150

100

50

Source: Ariel Corporation: compressor sizing protocol. (1) Assumes Discharge Pressure = 1,200 PSIG.

(HP)

0

350,000

300,000

250,000

200,000

150,000

100,000

50,000

0

Compression Throughout the Value Chain

Midstream Compression Offers Cash Flow & Customer Stability

Non-GAAP Reconciliations

($ in 000's)

Net income (loss)

Interest expense, net Depreciation and amortization Income tax expense

EBITDA

Interest income on capital lease Unit-based compensation expense (income) Transaction expenses

Severance charges

Loss (gain) on disposition of assets Impairment of compression equipment Impairment of goodwill

Adjusted EBITDA

Interest expense, net Non-cash interest expense Income tax expense

Interest income on capital lease Transaction expenses Severance charges Other

Changes in operating assets and liabilities Net cash provided by operating activities

$

Three Months Ended	Nine Months Ended
September 30,	June 30,	September 30,
2020	2020	2020

6,519 32,004 60,072 268

$

98,863

87

1,332

136

130

1,686

1,706 -

$

103,940

(32,004)

2,167

(268)

(87)

(136)

(130)

78

(25,341)

$

48,219

$

2,684 31,815 60,338 419

$

(593,258)

$

95,256

105 316

4,568 4,071

- 136

2,416 2,963

(787) (115)

3,923 5,629

-

$

96,297 179,172 983 (316,806)

619,411

$

105,481

(31,815) (96,297)

1,960 6,113

(419) (983)

(105) (316)

- (136)

(2,416) 2,349 22,320

$

97,355

$

315,605

(2,963)

4,050 (29,422)

$

195,651

Years Ended December 31,

($ in 000's)	2019	2018	2017	2016	2015	2014	2013	2012	2010	2009	2008	2007
Net income (loss)	39,132	(10,551)	11,440	12,935	$ (154,273)	24,946	11,071	4,503	$	69	$	10,479	$	21,228	$	20,911	$	7,122
Interest expense, net	127,146	78,377	25,129	21,087	17,605	12,529	12,488	15,905	12,970	12,279	10,043	14,003	16,468
Depreciation and amortization	231,447	213,692	98,603	92,337	85,238	71,156	52,917	41,880	32,738	24,569	22,957	18,016	13,437
Income tax expense (benefit)	2,186	(2,474)	538	421	1,085	103	280	196	155	155	190	119	155
EBITDA	399,911	279,044	135,710	126,780	(50,345)	108,734	76,756	62,484	45,932	47,482	54,418	53,049	37,182
Interest income on capital lease	672	709	1,610	1,492	1,631	1,274	-	-	-	-	-	-	-
Unit-based compensation expense	10,814	11,740	11,708	10,373	3,863	3,034	1,343	-	-	382	269	225	2,352
Transaction expenses	578	4,181	1,406	894	-	1,299	2,142	-	-	-	-	-	-
Severance charges	831	3,171	314	577	-	-	-	-	-	-	-	-	-
Loss (gain) on disposition of assets and other	940	12,964	(17)	772	(1,040)	(2,198)	637	-	-	-	-	-	-
Impairment of goodwill	-	-	-	-	172,189	-	-	-	-	-	-	-	-
Impairment of compression equipment	5,894	8,666	4,972	5,760	27,274	2,266	203	-	-	-	1,677	-	1,028
Equipment operating lease expense	-	-	-	-	-	-	-	-	4,053	2,285	553	-	-
Riverstone management fee	-	-	-	-	-	-	49	1,000	1,000	-	-	-	-
Restructuring charges	-	-	-	-	-	-	-	-	300	-	-	-	-
Fees and expenses related to the Holdings Acquisition	-	-	-	-	-	-	-	-	-	1,838	-	-	-
Adjusted EBITDA	419,640	320,475	155,703	146,648	153,572	114,409	81,130	63,484	51,285	51,987	56,917	53,274	40,562
Interest expense, net	(127,146)	(78,377)	(25,129)	(21,087)	(17,605)	(12,529)	(12,488)	(15,905)	(12,970)	(12,279)	(10,043)	(14,003)	(16,468)
Non-cash interest expense	7,607	5,080	2,186	2,108	1,702	1,189	1,839	(58)	(920)	3,362	288	201	1,666
Income tax (expense) benefit	(2,186)	2,474	(538)	(421)	(1,085)	(103)	(280)	(196)	(155)	(155)	(190)	(119)	(155)
Interest income on capital lease	(672)	(709)	(1,610)	(1,492)	(1,631)	(1,274)	-	-	-	-	-	-	-
Transaction expenses	(578)	(4,181)	(1,406)	(894)	-	(1,299)	(2,142)	-	-	-	-	-	-
Severance charges	(831)	(3,171)	(314)	(577)	-	-	-	-	-	-	-	-	-
Equipment operating lease expense	-	-	-	-	-	-	-	-	(4,053)	(2,285)	(553)	-	-
Riverstone management fee	-	-	-	-	-	-	(49)	(1,000)	(1,000)	-	-	-	-
Restructuring charges	-	-	-	-	-	-	-	-	(300)	-	-	-	-
Fees and expenses related to the Holdings Acquisition	-	-	-	-	-	-	-	-	-	(1,838)	-	-	-
Other	2,426	(2,030)	(490)	-	-	-	-	-	-	-	-	-	-
Changes in operating assets and liabilities	2,320	(13,221)	(3,758)	(20,588)	(17,552)	1,498	180	(4,351)	1,895	(220)	(3,474)	1,346	836
Net cash provided by operating activities

2011

$

$

$

$

$

$

$

$ 300,580

$ 226,340

$ 124,644

$ 103,697

$

117,401

$ 101,891

$ 68,190

$ 41,974

$ 33,782

$ 38,572

$ 42,945

$ 40,699

$ 26,441

Notes: Represents the results of operations of the USA Compression Predecessor only for the three months ended March 31, 2018 and the results of operations of the Partnership, which includes the USA Compression

Predecessor, for the nine months ended December 31, 2018. See Slide 2 for more detail.

Following the Transactions, the USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes. The information presented above under the heading "Pre-CDM Acquisition Non-Predecessor" represents information of USA Compression Partners, LP, which is not the predecessor of the Partnership, for periods prior to the Transactions and is presented for illustrative purposes only. See Slide 2 for more detail.

Three Months Ended

September 30,

($ in 000's)

Net income (loss)

Non-cash interest expense Depreciation and amortization Non-cash income tax expense Unit-based compensation expense Transaction expenses

Severance charges

Loss (gain) on disposition of assets Impairment of compression equipment Impairment of goodwill

Distributions on Preferred Units Proceeds from insurance recovery Maintenance capital expenditures Distributable Cash Flow

Maintenance capital expenditures Transaction expenses

Severance charges Distributions on Preferred Units Other

Changes in operating assets and liabilities Net cash provided by operating activities

2020

$

6,519

2,167

60,072

78

1,332

136

130

1,686

1,706 -

(12,188)

-

(4,727) 56,911

4,727

(136)

(130)

12,188 -

(25,341)

$

48,219

June 30, 2020

Nine Months EndedSeptember 30, 2020

$

2,684

1,960 6,113

60,338 179,172

149 350

4,568 4,071

- 136.00

2,416 2,963

(787) (115)

3,923 5,629

- (12,188)

- (4,377)

$

(593,258)

619,411 (36,563)

336 (17,946)

58,686 170,299

4,377 17,946

-

(136.00)

(2,416) (2,963)

12,188 36,563

2,200 3,364

22,320

(29,422)

$

97,355 $ 195,651

Distributable Cash Flow

Distributions for Distributable Cash Flow Coverage Ratio

Distributable Cash Flow Coverage Ratio

$ $

56,911 50,874 1.12x

$ $

58,686 $ 170,299

50,850 $ 152,503

1.15x

1.12x

2020 Guidance

Guidance

Net loss

Plus: Interest expense, net

Plus: Depreciation and amortization Plus: Income tax expense

EBITDA

Plus: Interest income on capital lease

Plus: Unit-based compensation expense and other Plus: Severance charges

Plus: Impairment of compression equipment Plus: Impairment of goodwill

Adjusted EBITDA

Less: Cash interest expense

Less: Current income tax expense

Less: Maintenance capital expenditures Less: Distributions on Preferred Units Distributable Cash Flow

$(600.0 million) to ($590.0 million)

128.0 million

240.0 million

1.0 million

$(231.0 million) to $(221.0 million)

0.5 million

7.5 million

3.0 million

5.6 million

619.4 million

$405.0 million to $415.0 million

120.0 million

1.0 million

25.0 million

49.0 million

$210.0 million to $220.0 million

Basis of Presentation; Explanation of Non-GAAP Financial Measures

This presentation includes the non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow and Distributable Cash Flow Coverage Ratio.

EBITDA, a measure not defined under U.S. generally accepted accounting principles ("GAAP"), is defined by USAC as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit). Adjusted EBITDA, which also is a non-GAAP measure, is defined by USAC as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital lease, unit-based compensation expense, restructuring/severance charges, management fees, expenses under our operating lease with Caterpillar, certain transaction fees, loss (gain) on disposition of assets and other. The Partnership's management views Adjusted EBITDA as one of its primary tools, to assess: (1) the financial performance of the Partnership's assets without regard to the impact of financing methods, capital structure or historical cost basis of the Partnership's assets; (2) the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; (3) the ability of the Partnership's assets to generate cash sufficient to make debt payments and pay distributions; and (4) the Partnership's operating performance as compared to those of other companies in its industry without regard to the impact of financing methods and capital structure. The Partnership believes that Adjusted EBITDA provides useful information to investors because, when viewed with GAAP results and the accompanying reconciliations, it provides a more complete understanding of the Partnership's performance than GAAP results alone. Management also believes that external users of its financial statements benefit from having access to the same financial measures that management uses in evaluating the results of the Partnership's business.

Adjusted gross margin, a non-GAAP measure, is defined as revenue less cost of operations, exclusive of depreciation and amortization expense. Management believes that Adjusted gross margin is useful as a supplemental measure of the Partnership's operating profitability. Adjusted gross margin is impacted primarily by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume and per unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates on compression units.

Distributable Cash Flow, a non-GAAP measure, is defined as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense, impairment of compression equipment, impairment of goodwill, certain transaction fees, severance charges, loss (gain) on disposition of assets, proceeds from insurance recovery and other, less distributions on the Partnership's Series A Preferred Units ("Preferred Units") and maintenance capital expenditures. The Partnership's management believes Distributable Cash Flow is an important measure of operating performance because it allows management, investors and others to compare basic cash flows the Partnership generates (after distributions on the Partnership's Preferred Units but prior to any retained cash reserves by the Partnership's general partner and the effect of the Distribution Reinvestment Plan ("DRIP")) to the cash distributions the Partnership expects to pay its common unitholders. See previous slides for Adjusted EBITDA reconciled to net income (loss) and net cash provided by operating activities, and net income (loss) reconciled to Distributable Cash Flow.

This presentation contains a forward-looking estimate of Adjusted EBITDA and Distributable Cash Flow projected to be generated by the Partnership in its 2020 fiscal year. A forward-looking estimate of net cash provided by operating activities and reconciliations of the forward-looking estimates of Adjusted EBITDA and Distributable Cash Flow to net cash provided by operating activities are not provided because the items necessary to estimate net cash provided by operating activities, in particular the change in operating assets and liabilities, are not accessible or estimable at this time. The Partnership does not anticipate the changes in operating assets and liabilities to be material, but changes in accounts receivable, accounts payable, accrued liabilities and deferred revenue could be significant, such that the amount of net cash provided by operating activities would vary substantially from the amount of projected Adjusted EBITDA and Distributable Cash Flow.

Adjusted EBITDA, Adjusted gross margin and Distributable Cash Flow should not be considered an alternative to, or more meaningful than, net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, Adjusted EBITDA, Adjusted gross margin and Distributable Cash Flow as presented may not be comparable to similarly titled measures of other companies because other entities may not calculate such measures in the same manner.

The Partnership believes that external users of its financial statements benefit from having access to the same financial measures that management uses in evaluating the results of the Partnership's business.

Distributable Cash Flow Coverage Ratio, a non-GAAP measure, is defined as Distributable Cash Flow divided by distributions declared to common unitholders in respect of such period. We believe Distributable Cash Flow Coverage Ratio is an important measure of operating performance because it allows management, investors and others to gauge our ability to pay cash distributions to common unitholders using the cash flows we generate. Our Distributable Cash Flow Coverage Ratio as presented may not be comparable to similarly titled measures of other companies.