PDC Energy : 06janAll Day

GOLDMAN SACHS

GLOBAL ENERGY CONFERENCE

January 2021

Forward-Looking Statements

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this presentation are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; our currently suspended stock repurchase program; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; impacts of Colorado political matters, including recent rulemaking initiatives given our geographic concentration; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; and our ability to repay our 2021 Convertible Notes.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this release reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the term "projection" or similar terms or expressions or indicate that we have "modeled" certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in our Quarterly Report on Form 10-Q, our Annual Report on Form

10-K for the year ended December 31, 2019 filed with the U.S. Securities and Exchange Commission ("SEC") on February 26, 2020 (the "2019 Form 10-K"), our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 8, 2020 (the "First Quarter 2020 Form 10-Q"), our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the SEC on August 6, 2020 (the "Second Quarter 2020 Form 10- Q"), our Quarterly Report on Form 10-Q for the third quarter ended September 30, 2020 filed with the SEC on November 5, 2020 (the "Third Quarter 2020 Form 10-Q") and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this presentation. We undertake no obligation to update any forward-lookingstatements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-lookingstatements are qualified in their entirety by this cautionary statement.

January 2021	2

Reconciliation of Non-U.S. GAAP Financial Metrics

We use "adjusted cash flows from operations," "adjusted free cash flow (deficit)," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.

We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.

Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.

Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development and acquisitions and to service our debt obligations.

Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology.

January 2021	3

PDC Strategy Focused on Significant Value-Creation

Top Priorities in

Demand Destruction

World

Wattenberg Field

161,000 Boe/d(2)

Delaware Basin

31,500 Boe/d(2)

	PDC Market Snapshot(3)
	Nasdaq Symbol	PDCE
	Market Cap	$2.0 billion
On hold in	Net Debt	$1.6 billion
Demand Destruction	Enterprise Value	$3.6 billion
World	Shares Outstanding	100 million
	Total Liquidity	~$1.4 billion

January 2021	(1)	Adjusted FCF defined as net cash from operating activities, before changes in working capital, less oil & gas capital investments. See appendix for reconciliation.	4
(2)	Production = 3Q20; (3) Market cap, Enterprise Value, liquidity and shares outstanding as of 12/31/20.

Third Quarter Results Emphasize Valuation Disconnect

3rd Quarter Highlights

• ~$280 million of net cash from operating activities
• • Generated ~$225 million of adjusted free cash flow (FCF)(1)
  • 3Q20 FCF represents > 10% of current market cap(2)
• ~$35 million capital investments
• • Operated one DJ drilling rig and resumed DJ completions in September
• Paid down ~$215 million of debt in 3Q
• • Represents > 5% current Enterprise Value(2)

Permit Update

• 32 additional permits approved in September & October
• Expect ~475 combined DUCs & approved permits at YE20
• Anticipate more approved permits prior to year-end
• Anticipate Mission Change rulemaking related to siting requirements to be finalized in late November and effective mid-January

• Continue to effectively drive down costs - LOE + G&A < $4 per Boe
• • Synergies of SRC merger demonstrated through LOE of $2.11/Boe and G&A of $1.84/Boe

January 2021	(1) Adjusted free cash flow (FCF) defined as net cash from operating activities, before changes in working capital, less oil & gas capital investments. See appendix for	5
reconciliation. (2) Market cap and Enterprise Value as of 12/31/20 of ~$2,000 and ~$3,600, respectively.

Resilient Balance Sheet with Strong Hedge Book

Liquidity Update

(as of December 31, 2020)

• Borrowing base and commitment level of $1.6 billion (post-Fall redetermination in October 2020)
• Borrowings under revolver of ~$285 million at 3Q
• • Paid down ~$215 million of debt in 3Q20
  • Paid down ~$115 million of debt in 4Q20
• Liquidity of ~$1.4 billion

Hedging Update

(as of December 31, 2020)

• ~60% of 2021 crude hedged at $45.00 WA floor
• ~55% of 2021 nat. gas hedged at $2.40 WA floor
• 5.8 MMBbls of 2022 crude hedged at $40.00 WA floor
• 26.0 MMBtu of 2022 natural gas hedged at $2.50 WA floor

Total Debt: ~$1.6 billion

(as of 12/31/20)

$2,000

Revolver

(Commitment Level)

$1,500

						5.75%
$1,000						Senior
					Notes
				6.125%		$750MM
	1.125%			Senior
			Notes	6.25%
$500	Convertible			$400MM
	Notes				Senior
	$200MM		~$170MM		Notes
				$100MM
$0
	2021	2022	2023	2024	2025	2026	2027	2028

January 2021	6

Project Significant FCF at $35 Oil

• Capital investment range to $500 - $550 million
• • Expect ~$110 million in 4Q
  • Wattenberg - one rig and one completion crew planned
  • Delaware - minimal planned activity through year-end
• Anticipate FCF of more than $350 million(1)
• Full-yearoil production of 64,000 - 68,000 Bbls/d and total production of 175,000 - 185,000 Boe/d
• • Anticipate < 10% sequential decline in 4Q20
  • Quarterly exit rates of ~175,000 Boe/d and ~60,000 Bbls/d

2020e Capital Investments

(millions)

$1,000 - $1,100

$500 - $600

$500 - $550

2020e (February)2020e (May)2020e (August)

Net Oil Pricing Summary

$/Bbl	2019	1Q20	2Q20	3Q20	4Q20e	2021e
NYMEX Oil	$57.03	$46.17	$27.85	$40.93	$35.00	$40.00
Deduct(2)	($3.77)	($3.86)	($9.22)	($3.44)	($3 - $4)	($2	- $4)
Gross Realized (% of NYMEX)	93%	92%	67%	92%	~90%	90 - 95%
TGP	($1.24)	($1.46)	($1.87)	($3.00)	($3.00)	($2	- $4)
Realized Netback	$52.01	$40.86	$16.76	$34.49	$28 - $29	$32	- $36

January 2021	(1) Assumes 4Q20 pricing of $35/Bbl WTI, $2.50/Mcf NYMEX natural gas and NGL realizations of ~$10/Bbl. (2) Includes anticipated quality, roll and transport differentials,	7
which vary by contract.

Multi-Year Focus on Sustainable FCF Generation

All Numbers Approximate

2020 + 2021 Highlights

• Anticipate 2-year cumulative capital investments of ~$1.1 billion
• ~$850 million of projected FCF between 2H19 and YE21
• • Increase to initial SRC acquisition projections despite dramatic decrease in pricing
  • Have generated FCF in 4 of the past 5 quarters
  • Project ~400 million FCF over next 5 quarters on ~$650 million capital investment
• Balance sheet strength and low absolute debt level remains top priority
• • Better positioned for incremental, sustainable return-of- capital initiatives
  • 2020 Guidance and 2021 Outlook each reflect re-investment rate below 70% at ~$40/Bbl oil

Significant FCF Generation

(millions)

$350+

$300

$200

		PDC Standalone
		$56.71/Bbl		$35.00/Bbl (4Q)	$40.00/Bbl
		$2.36/Mcf		$2.50/Mcf	$2.75/Mcf
		2H19		2020e	2021e
		FCF Yield(2)	~20%	~20%
		FCF/EV Yield(2)	~10%	~10%
		FCF Margin	66%	55%

FCF Sensitivity

Change	4Q20	2021
+/- $2.50/Bbl WTI	< $5 MM	$35 MM
+/- $0.25/MMbtu Gas	< $5 MM	$15 MM
+/- $1.00/Bbl NGL	< $5 MM	$15 MM

January 2021	(1) Assumes 4Q20 pricing of $35/Bbl WTI, $2.50/Mcf NYMEX natural gas and NGL realizations of ~$10/Bbl. 2021 pricing of $40/Bbl WTI, $2.75/Mcf NYMEX natural gas and	8
NGL realizations of ~$10/Bbl. (2) Market cap and Enterprise Value as of 12/31/20. Debt balance of ~$1.6 billion.

Commitment to Corporate Social Responsibility

Published Inaugural Sustainability Report in Alignment with SASB Standards

Responsible	Environmental		Social		Corporate
Operations	Stewardship		Impact		Governance

52%	84%	2,285	> 50%
Year-over-year decrease in Total Recordable	Reduction in methane emissions per Boe	Volunteer hours by PDC employees in 2019	Office-based employees that are women
Incident Rate	since 2016	Energize Our Community Day
29	260,000	90	50%
Average hours of annual health and safety	Reduced truckloads per year due to	Organizations across four states that	Board refreshment over the past five years
training for field employees	increased oil and water piping	received PDC donations
January 2021				9

ASSET OVERVIEW

Key Statistics

785

YE19 PF Proved Reserves

(MMBoe)

~161,000

3Q20 Production

(Boe/d)

33%

3Q20 Crude Oil

(Production)

$1.89

January 2021	3Q20 LOE/Boe

Wattenberg Overview

Prairie Area

Summit Area

Kersey Area

Plains Area

~180,000 Net Acres

• Currently operating one rig and one completion crew
• Anticipate 1 rig and 1 full-time completion crew in 2021

11

Attaining Colorado Permits Amidst Ongoing Rulemaking Discussions

• Project to exit 2020 with ~275 well permits (Form 2) secured through 23 approved surface location permits (Form 2A)
• • 85% of approved surface locations were approved under the COGCC's Director's Objective Criteria
  • Average proximity to nearest BU of ~800'
• Received approval for 32 well permits in September and October (4 surface locations)
• • Each surface location contained an average ~10 Building Units (BU) within 2,000'
  • Average proximity to nearest BU of ~750'
• Potential for additional approved permits prior to new rulemaking effective date

Area	2020 Spuds	2020 TILs	YE20 DUCs	YE20 Permits
Kersey	20%	25%	40%	35%
Summit	60%	60%	40%	40%
Plains	5%	10%	15%	10%
Prairie	15%	5%	5%	15%
Total	100	130	~200	~275

Key Takeaways

• Successful track record of attaining permits under the
  Director's Objective Criteria
• Expected ~475 DUCs and approved permits at YE20 reflect ~4 years of TIL activity at current pace

January 2021	12

Capital Efficiency Gains Contributing to Lower Projected Well Costs

• Continued improvements to Wattenberg completions
• • Recent completion activity averaging ~20 stages per day
  • Consistently improving non-productive time per day
• 2020 XRL drill times more than 20% faster than early 2019 performance
• • Average spud-to-spud XRL drill times of 6 days
• Expect 5-10% improvement on projected well costs from current $400/ft. (DJ) and $850/ft. (DE) estimates
• • Balancing potential per well savings with ability to D&C more Wattenberg wells

Wattenberg Completions Efficiency(1)

(Hours per day Completing)

85%

					82%
80%
	76%		77%
75%	73%		74%
70%
65%
60%
1Q19	2Q19	3Q19	1Q20	3Q20

Wattenberg Drill Times(1)

(XRL, Spud-to-Spud)

	12
	9
Days	6
	3
	0
	1H19 = 7.7 days	2H19 = 7.5 days	1H20 = 6.0 days

January 2021	(1) The Company did not have any completions activity in 4Q19 or 2Q20 and did not drill any XRL wells in 3Q20	13

Key Statistics

Delaware Basin Overview

120

YE19 Proved Reserves

(MMBoe)

~31,500

3Q20 Production

(Boe/d)

39%

3Q20 Crude Oil

N. Central

Reeves County

Loving County

Pecos

Block 4

(Production)

$3.21

~25,000 Net Acres

• No significant activity planned through year-end
• Anticipate 1 full-time rig and 15-20 TILs in 2021

January 2021	3Q20 LOE/Boe	14

Consistent, Successful Execution of Transparent Strategy

Track Record of Operational and Financial Execution Positions PDC for Sustainable Value-Creation

Ability to generate consistent, sustainable adjusted free cash flow

• Project to generate more than $400 million FCF between 4Q20 and YE21 with positive FCF expected in each of next 5 quarters(1)

Focus on maintaining strong balance sheet and low cost structure

• Focus on reducing absolute debt level to ~$1.5 billion to enable sustainable shareholder friendly initiatives and continued debt pay down

Improved DJ midstream environment

• Lower line pressures with ample capacity lead to improved well productivity

Confident in executing Colorado development plan

• ~4 years of TIL activity secured through DUCs and approved permits with track record of successfully working with COGCC

Resilient 5-year outlook

• FCF yield, leverage and cost structure to compete with broad market

January 2021	(1) Assumes 4Q20 pricing of $35/Bbl WTI, $2.50/Mcf NYMEX natural gas and NGL realizations of ~$10/Bbl. 2021 pricing of $40/Bbl WTI, $2.75/Mcf NYMEX natural gas and	15
NGL realizations of ~$10/Bbl.

Investor Relations

Kyle Sourk, Sr. Manager Corporate Finance & Investor Relations [e-mail]

Corporate Headquarters	Website
PDC Energy, Inc.	www.pdce.com
1775 Sherman Street
Suite 3000
Denver, Colorado 80203
303-860-5800

APPENDIX

Current Colorado Permit Process

Average ~12 Months from Permit Submittal to Approval (steps 3-4)

1. Site Selection Process - Surface Owner	3. Submit Form 2A Application - COGCC	5. PERMIT APPROVED
- Field land and surface owner agree on pad location	- Submit application for approval of surface location	- 2 years to commence operations
- Alternative location analysis		- Does not include specific well approval
- Access roads & facility/tank locations	Best Mgmt.	- Includes planned # of wells on location
- Oil, gas, water & power connections	- Receive Form 2A Approval - ~6 months (move to step 4)

Practices (BMPs)

- Dust & sound mitigation - Safety protocol

- Sign Surface Use Agreement (SUA) (move to step 2)

2. Data Gathering & Local Review - Local Gov't.	4. Submit Form 2 Application - COGCC
- Compile leaseholder & mineral owner information	- Submit application for each specific well (below ground)
-	Notify all BU owners within 2,000' - include estimated drill date	-	Casing design
-	Submit local government permit application to municipality or Weld County	- Cement usage and mud weights
	- Municipality = Use by Special Review (USR)	-	Receive Form 2 Approval - ~6 months

• - Weld County = Weld Oil & Gas Location Assessment (WOGLA)

• Analysis of BMPs
• Receive 'Local Government Approval' to proceed with COGCC permit application (move to step 3)

January 2021	18

Current COGCC Rulemaking Update

SB-181 Rules Related to Setback and Siting Requirements Expected to be Finalized in Late November

• Current proposal of new rules viewed as extremely similar to existing Director's Objective Criteria
• • 500' setback from Building Unit (BU)
  • 2,000' setback from School Facilities and Child Care Centers
  • "Siting requirementsfor proposed oil & gas locations within 2,000' of one BU or high occupancy BU" replaces "Director's Objective Criteria"
  • Oil & Gas Development Plans (OGDP) and Comprehensive Area Plans (CAP) - multiple surface location permits (Form 2A's) with extended permit life

Must satisfy one of four criteria to obtain Surface Location Permit (Form 2A)

1. No BU's within 2,000' of proposed location - ~5% of PDC's undeveloped inventory
2. Unanimous BU owner/BU tenant acknowledgment
3. Location is within a Comprehensive Area Plan (CAP)
4. COGCC Commission hearing determines equivalent protections exist at distances closer than 2,000'
5. • Best Management Practices - consistent with current PDC practices
   • Local Government consideration - consideration of local government decision - consistent with current USR/WOGLA approval
   • Alternative site analysis - consistent with current PDC site selection process
   • Relation to larger development plans - consistent with PDC emphasis on long-term planning & reducing surface footprint, increased piping, etc.
   • Plans to avoid, minimize and mitigate impacts on residential BU's - consistent with current PDC noise and dust mitigation efforts
   • Community Outreach - consistent with current PDC practices discussed in 2020 Sustainability Report
   • Staff recommendation - COGCC staff to offer Formal Consultation Process with Municipality/Weld County

Minimal anticipated changes to individual well/below ground (Form 2) approval process

January 2021	19

Rural Weld County Position with Low Building Unit (BU) Density

• PDC acreage is 100% in Weld County, Colorado
• • ~80% in unincorporated Weld County (not within Municipal boundaries)
• Extremely rural acreage position with low BU density increases potential to achieve unanimous consent
• • ~90% of unpermitted inventory has < 20 BU's within 2,000' compared to ~85% of permitted inventory

BU's within 2,000'	0	1-10	11-20	21-35	35+
Permitted Inventory	0%	75%	10%	5%	10%
Unpermitted Inventory	5%	60%	25%	5%	5%

PDC Inventory in Relation to Nearest BU

(Does Not Include DUCs)

Key Takeaway

• Unpermitted and permitted inventory have very consistent BU density and proximity to nearest Building Unit

*All numbers approximate and do not include surface pad optimization which has potential to further improve numbers*

January 2021	20

Continued Emphasis on Cost Management

Targeting combined LOE + G&A of < $5/Boe

• Merger synergies and focus on costs reflected through anticipated year-over-year reduction of 20+% in LOE+G&A/Boe
• Anticipated LOE of $160 - $165 million
• G&A expected between $135 - $140 million
• • Includes ~$25 million of stock-based comp
  • Includes ~$10 million of SRC transition-related expense
  • Excludes ~$20 million of SRC deal costs
• Anticipate TGP of $1.00 - $1.15/Boe
• Production taxes of 5% - 6% of sales

(1) Excludes ~$20 million of SRC deal costs in 1Q20

January 2021

	LOE + G&A ($/Boe)
	LOE	G&A
$8.00	$7.51
$6.60		$6.15
$6.00
$4.25			(1)
$3.78	$3.27	~$4.50
$4.00			$2.05
$2.00	$3.26	$2.88
$2.82	$2.45
$0.00
2017	2018	2019	2020e

LOE + G&A ($/Boe)

LOE G&A

$6.00 $5.44(1)

	$2.50	$4.13	$3.95	~$4.20
$4.00
		$2.05	$1.84	$1.70
$2.00
	$2.94	$2.08	$2.11	$2.50
$0.00
	1Q20	2Q20	3Q20	4Q20e

21

Detailed Hedge Positions

As of 12/31/20

January 2021	22

Modified 2020 STI Compensation Metrics

PDC Board of Directors modified 2020 executive STI quantitative metrics in May 2020 in response to demand destruction

• Reduced target payout and maximum payout percentages
• Maintain current weightings:
• • 75% quantitative / 25% qualitative
• Added Leverage Ratio to emphasize importance of balance sheet strength in low commodity price environment
• Removed production to better align with industry demands and account for unknown curtailment period
• G&A + LOE metric now measured in millions instead of per Boe to further de-emphasize production

12.5%

each

2020 Proxy

• EHS
• Free cash flow margin
• G&A + LOE per Boe
• CROCI
• Production
• Capital efficiency/F&D

		2020 Revised (May)
	−	EHS
	− Free cash flow (absolute millions)
15%	− G&A + LOE (absolute millions)
each
−	CROCI
	−	Leverage Ratio (New)
	−	Production (No weighting)
	−	F&D (No weighting)

January 2021	23

Adjusted Free Cash Flow & Adjusted Earnings Reconciliations

Cash Flows from Operations to Adjusted Cash Flows from Operations and Adjusted Free Cash Flow (Deficit)

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2020				2019				2020				2019
Cash flows from operations to adjusted cash flows from
operations and adjusted free cash flow (deficit):
Net cash from operating activities	$	280.1	$	233.5	$	649.3	$	651.0
Changes in assets and liabilities		(18.7)				(31.1)				3.5				(49.1)
Adjusted cash flows from operations		261.4				202.4				652.8				601.9
Capital expenditures for development of crude oil and natural		(57.6)				(237.8)				(445.5)				(755.8)
gas properties
Change in accounts payable related to capital expenditures for		24.2				74.2				31.4				32.9
oil and gas development activities
Adjusted free cash flow (deficit)	$	228.0	$	38.8	$	238.7	$	(121.0)
Net Loss to Adjusted Net Income (Loss) and Adjusted Earnings Per Share, Diluted
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2020				2019				2020				2019
Net income (loss) to adjusted net income (loss):
Net income (loss)	$	(30.8)	$	15.9	$	(717.6)	$	(35.7)
Loss (gain) on commodity derivative instruments		68.1				(54.9)				(245.9)				87.9
Net settlements on commodity derivative instruments		66.9				1.8				227.5				(19.8)
Tax effect of above adjustments (1)		-				12.7				-				(16.3)
Adjusted net income (loss)	$	104.2	$	(24.5)	$	(736.0)	$	16.1
Earnings per share, diluted	$	(0.31)	$	0.25	$	(7.34)	$	(0.55)
Loss (gain) on commodity derivative instruments		0.68				(0.87)				(2.52)				1.35
Net settlements on commodity derivative instruments		0.67				0.03				2.33				(0.30)
Tax effect of above adjustments (1)		-				0.20				-				(0.25)
Adjusted earnings per share, diluted	$	1.04	$	(0.39)	$	(7.53)	$	0.25
Weighted-average diluted shares outstanding		100.2				62.5				97.8				64.9

January 2021	24

Reconciliation Non-U.S. GAAP Metrics

Adjusted EBITDAX

Three Months Ended		Nine Months Ended
September 30,		September 30,
2020		2019		2020		2019

Net income (loss) to adjusted EBITDAX:

Net income (loss)	$
Loss (gain) on commodity derivative instruments
Net settlements on commodity derivative instruments
Non-cashstock-based compensation
Interest expense, net
Income tax expense (benefit)
Impairment of properties and equipment
Exploration, geologic and geophysical expense
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Loss (gain) on sale of properties and equipment
Adjusted EBITDAX	$
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$
Interest expense, net
Amortization of debt discount and issuance costs
Exploration, geologic and geophysical expense
Other
Changes in assets and liabilities
Adjusted EBITDAX	$

(30.8) $

68.1

66.9

5.4

21.0

0.2

1.2

0.2

144.5

2.4

(0.3)

278.8 $

1. $
   (3.6)
   (0.2)

(18.7)

278.8 $

1. $
   (54.9)

214.7 $

1. $
   (3.4)
   (2.3)

(31.1)

214.7 $

(717.6)	$	(35.7)
(245.9)		87.9

227.5(19.8)

17.418.1

67.053.7

(3.5)(4.2)

882.337.0

1.03.5

470.2491.8

7.4		4.5
(0.6)		9.6
705.2	$	646.4
649.3	$	651.0

67.053.7

(12.5)	(10.1)
1.0	3.5
(3.1)	(2.6)

1. (49.1)

1. $ 646.4

January 2021	25

Reconciliation of Non-U.S. GAAP Metrics

Beginning in 3Q19, the Company modified its adjusted EBITDAX reconciliation to exclude (Gain) loss on sale of properties and equipment

Net income (loss) to adjusted EBITDAX (in millions):		3Q19		4Q19		1Q20		2Q20		3Q20
Net income (loss)	$	15.9	$	(21.0)	$	(465.0)	$	(221.8)	$	(30.8)
(Gain) loss on commodity derivative instruments		(54.9)		74.9		(434.7)		120.8		68.1
Net settlements on commodity derivative instruments		1.8		2.2		45.8		114.8		66.9
Non-cashstock-based compensation		5.9		5.7		5.7		6.4		5.4
Interest expense, net		17.8		17.4		24.2		21.8		21.0
Income tax expense (benefit)		10.7		0.9		(7.7)		4.1		0.2
Impairment of properties and equipment		0.2		1.5		881.1		-		1.2
Exploration, geologic and geophysical expense		0.2		0.6		0.1		0.7		0.2
Depreciation, depletion and amortization		171.8		152.4		176.2		149.5		144.5
Accretion of asset retirement obligations		1.4		1.6		2.6		2.4		2.4
(Gain) loss on sale of properties and equipment		43.9		0.1		(0.2)		(0.2)		(0.3)
Adjusted EBITDAX	$	214.7	$	236.3	$	228.1	$	198.5	$	278.8

January 2021	26

Definition

Adjusted FCF - Free Cash Flow (cash flows from operations before changes in working capital, less capital investments)

AMI - Area of Mutual Interest

Bbl - Barrel

Boe - Barrel of oil equivalent

BU - Building Unit

Btu - British thermal unit

CAGR - Compound Annual Growth Rate

CFPS - Cash flow per share

COGCC - Colorado Oil & Gas Commission

CWC - Completed well cost

D&C - Drilling and Completions

EBITDAX - Earnings before interest, taxes, depreciation, amortization and exploration

EUR - Estimated Ultimate Recovery

FCF Margin - Adjusted free cash flow divided by capital investments

Gross Margin - Oil, gas and NGL sales less LOE, TGP and prod. tax, as a % of oil, gas and NGL sales

Leverage Ratio - as defined in our revolving credit facility agreement; similar to Debt to EBITDAX

LOE - Lease operating expenses

1. - Million

MMcf - Million cubic feet

RoR - Rate of Return

SRL/MRL/XRL - Standard-, Mid- and Extended-reach lateral

SWD - Salt-water disposal

TGP - Transportation, gathering and processing

TIL - Turn-in-line

January 2021	27