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(66.1 net) proved plus probable undeveloped reserves locations identified by McDaniel & Associates Consultants Ltd., an independent petroleum consulting firm, ("McDaniel"), 166 gross (44.5 net) unbooked potential future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators and considered economic, and 155 gross (120.7 net) unbooked potential future drilling locations not associated with any reserves of the properties which have been identified by internal qualified reserves evaluators as offering future development potential but with marginal economics based on the current assessment. The Acquired Assets are all located in North Dakota, with most of its interests being in the Little Knife, Murphy Creek and Russian Creek areas. See "Description of the Acquired Assets" in this material change report.

The Purchase Agreement

The following is a summary of the material terms of the Purchase Agreement.

The Purchase Agreement provides for the acquisition by Enerplus USA of the Acquired Assets for the Purchase Price, payable in cash on the closing date of the Acquisition, currently anticipated to be on or about May 18, 2021 (the "Acquisition Closing Date"). The Purchase Price is subject to certain customary adjustments including, among other things, for certain title and environmental defects and for certain operating costs and expenses between the March 1, 2021 effective date of the Acquisition and the Acquisition Closing Date. Subject to certain customary exceptions, Enerplus USA will generally be entitled to receive all revenues and benefits arising from the Acquired Assets, and will be responsible for all obligations and expenditures in respect of the Acquired Assets, from and after the effective date of the Acquisition. An interim estimate of all adjustments required pursuant to the Purchase Agreement will be prepared by the Vendor on the Acquisition Closing Date, and a final settlement statement will be prepared by the Vendor within 90 days of the Acquisition Closing Date, which will be subject to final approval by Enerplus USA.

The Purchase Agreement contains a covenant in favour of Enerplus USA that allows Enerplus USA to conduct due diligence on the Acquired Assets prior to the Acquisition Closing Date, including providing Enerplus USA with reasonable access to the Acquired Assets and records relating thereto, and to conduct a Phase I environmental review thereof. In certain limited circumstances, Enerplus USA may seek Vendor's consent to conduct a Phase II environmental review, which consent may be withheld in Vendor's sole discretion; provided, however, if Vendor withholds such consent, subject to certain conditions, Enerplus USA may elect to exclude the affected assets and reduce the Purchase Price by the allocated value of the assets so excluded. Title and environmental defects that exceed certain minimum thresholds shall result in a downward adjustment to the Purchase Price by the amount that such defects exceed a deductible of 4% of the Purchase Price. If the net amount of title defects (as offset by any title benefits) and environmental defects (in each case, subject to a minimum threshold and aggregate deductible), exercised preferential rights, unobtained consents, assets excluded due to Vendor's refusal to consent to a Phase II and casualty losses resulting in a downward adjustment to the Purchase Price exceeds 15% of the Purchase Price, then either Enerplus USA or the Vendor may terminate the Purchase Agreement.

The Purchase Agreement contains customary conditions to closing of the Acquisition including, but not limited to: (a) the accuracy of each party's representations and warranties, and the performance of their respective covenants; and (b) no legal proceedings that would prohibit or seek substantial damages in connection with the Acquisition are pending before any governmental authority. In addition, the Purchase Agreement may be terminated by either party if the Acquisition Closing Date has not occurred by June 18, 2021.

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Enerplus USA has provided the Vendor with a deposit in the amount of US$31.2 million in support of its obligations pursuant to the Purchase Agreement (the "Deposit"). If the Acquisition is consummated, the Deposit will be applied towards the Purchase Price. If the Acquisition does not close due to a willful breach by Enerplus USA of the Purchase Agreement, or if Enerplus USA elects not to close the Acquisition despite all conditions to closing being satisfied or waived, the Vendor can either seek (a) to retain the Deposit or (b) specific performance. If the Acquisition does not close due to a willful breach by the Vendor of the Purchase Agreement, or if the Vendor elects not to close the Acquisition despite all conditions to closing being satisfied or waived, Enerplus USA can either seek (a) return of the Deposit, in addition to pursuing damages from the Vendor in an amount up to the amount of the Deposit, or (b) specific performance.

The Vendor has agreed to indemnify Enerplus USA for a period of twelve months from the Acquisition Closing Date in respect of certain losses and liabilities arising out of breaches of representations and warranties or a failure to perform covenants due to be performed prior to closing, subject to certain exceptions, including certain title warranties of the Vendor that will survive for two years. Enerplus USA has agreed to indemnify the Vendor after closing from and against any liabilities arising out of the ownership and operation of the Acquired Assets (whether before or after the Acquisition Closing Date), unless relating to a matter for which the Vendor has agreed to indemnify Enerplus USA. These indemnities are subject to certain limited exceptions, minimum thresholds and maximum amounts, in a manner which is customary for agreements of this type.

Description of the Acquired Assets

Outlined below is a description of crude oil and natural gas properties associated with the Acquired Assets, all of which are located in North Dakota. Primary U.S. crude oil properties associated with the Acquired Assets are located in the Little Knife, Murphy Creek and Russian Creek regions of North Dakota.

The Acquired Assets contain approximately 78,700 largely contiguous net acres of land in Little Knife, in Dunn County. On a production basis, approximately 65% of the Little Knife's properties comprising the Acquired Assets are operated. The Little Knife property produces a tight oil with some associated shale gas and NGLs, from both the Middle Bakken and Three Forks formations. Little Knife production averaged approximately 6,545 BOE/day in 2020 consisting of approximately 4,810 bbls/day of tight oil, approximately 811 bbls/day of NGLs and approximately 5,547 Mcf/day of shale gas. In the Little Knife region, 0.4 net wells were brought on-stream in 2020. In addition, 0.8 net wells were drilled in 2020 targeting the Middle Bakken and Three Forks formations and remain yet to be completed. Enerplus expects these 0.8 net drilled uncompleted wells to be completed and brought on production in 2021.

The Acquired Assets also contain working interests in the Murphy Creek and Russian Creek regions, which produced an average of approximately 622 BOE/day from the Middle Bakken formation in 2020, consisting of approximately 585 bbls/day of tight oil, approximately 26 bbls/day of NGLs and approximately 71 Mcf/day of shale gas.

Overall, the Acquired Assets produced an average of approximately 7,170 BOE/day in 2020 (75% tight oil, 12% NGLs and 13% shale gas). Total proved plus probable reserves associated with the Acquired Assets as at March 1, 2021 were approximately 62.7 MMBOE (49.7 MMbbls of tight oil, 7.1 MMbbls of NGLs and 35.1 Bcf of shale gas), as described in more detail below under " – Summary of Oil and Gas Reserves".

In 2020, the Vendor incurred capital expenditures (essentially all of which were development costs and not exploration costs) of approximately US$1.5 million in respect of the Acquired Assets. The Corporation

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anticipates that spending by the Corporation on these properties in 2021 following completion of the Acquisition will be in the range of US$15 million to US$20 million.

Summary of Principal Production Locations

The following table describes the average daily production from the principal producing properties and regions comprising the Acquired Assets during the year ended December 31, 2020.

Average Daily Production from Principal Properties and Regions

	Products
Property/Region	Tight Oil	NGLs	Shale Gas	Total
	(bbls/day)	(bbls/day)	(Mcf/day)	(BOE/day)
Little Knife, North Dakota	4,810	810	5,550	6,545
Murphy Creek, North Dakota	585	25	70	620
Russian Creek, North Dakota	3	-	2	3
Total	5,400	835	5,620	7,170

Quarterly Production History

The following table sets forth average daily gross production volumes associated with the Acquired Assets by product type, for each fiscal quarter in 2020 and for the entire year. Production decreased significantly after the second quarter of 2020 due to commodity price-related oil production curtailments and minimal development capital spending on the properties.

	Year Ended December 31, 2020
Product Type	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Annual
Tight oil (bbls/day)	6,380	5,690	4,770	4,745	5,400
Natural gas liquids (bbls/day)	760	1,050	755	785	835
Total liquids (bbls/day)	7,140	6,740	5,525	5,530	6,240
Shale gas (Mcf/day)	5,310	6,770	4,685	5,710	5,620
Total (BOE/day)	8,030	7,870	6,310	6,480	7,170

Exploration and Development Activities

In 2020, there were two gross (0.3 net) crude oil wells drilled on properties comprising the Acquired Assets.

Oil and Natural Gas Wells and Unproved Properties

As at March 1, 2021, there were 386 gross (113.6 net) producing oil wells and 49 gross (9.9 net) non-producing oil wells, which are not producing but may be capable of production, associated with the Acquired Assets. Enerplus expects that no rights to explore, develop and exploit on unproved properties associated with the Acquired Assets will expire, in the ordinary course, prior to December 31, 2021. Enerplus does not believe that a material portion of unproved properties associated with the Acquired Assets are scheduled to expire in the near term, or would require material expenditures to be made or work conducted in the near term to preserve the rights associated with those properties.

For any properties with no reserves or on unproved lands associated with the Acquired Assets, Enerplus does not believe such assets have any significant abandonment and reclamation costs, unusually high expected development costs or operating costs, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations.

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Summary of Oil and Gas Reserves

All of the reserves associated with the Acquired Assets have been independently evaluated for the Corporation in accordance with NI 51-101 by McDaniel, with an effective date of March 1, 2021 (the "McDaniel Report"). McDaniel used the average of the commodity price forecasts and inflation rates of GLJ Petroleum Consultants ("GLJ"), McDaniel and Sproule Associates Limited ("Sproule") as of January 1, 2021 to prepare its report.

The following sections and tables summarize, as of March 1, 2021, tight oil, NGLs and shale gas reserves associated with the Acquired Assets and the estimated net present values of future net revenues associated with such reserves, together with certain information, estimates and assumptions pertaining to such reserves estimates. The data contained in the tables is a summary of the evaluation and, as a result, the tables may contain slightly different numbers than the evaluation due to rounding. Additionally, the columns and rows in the tables may not add due to rounding.

All estimates of future net revenues are stated prior to provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures. Such estimates are also presented before deducting income taxes as the McDaniel Report evaluated the Acquired Assets on a stand-alone basis, without considering corporate tax rates or tax pools of the Vendor or the Corporation. With respect to pricing information in the following reserves information, the wellhead oil prices were adjusted for quality and transportation based on historical actual prices. The natural gas prices were adjusted, where necessary, based on historical pricing based on heating values and transportation. The NGLs prices were adjusted to reflect historical average prices received.

It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The reserves estimates of tight oil, NGLs and shale gas reserves associated with the Acquired Assets provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein.

The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to reserves associated with the Acquired Assets as of March 1, 2021, using forecast price and cost cases.

Summary of Oil and Gas Reserves (Forecast Prices and Costs)

As of March 1, 2021

	OIL AND NATURAL GAS RESERVES
RESERVES CATEGORY	Tight Oil		Natural Gas Liquids		Shale Gas		Total
RESERVES CATEGORY		Gross	Net	Gross	Net	Gross	Net	Gross	Net
	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(MBOE)	(MBOE)
Proved Developed Producing	11,321	9,037	1,765	1,409	8,828	8,468	14,556	11,857
Proved Undeveloped	16,792	13,312	2,753	2,180	13,305	12,989	21,762	17,657
Total Proved	28,113	22,349	4,517	3,589	22,133	21,457	36,319	29,514
Probable	21,636	17,280	2,561	2,043	12,967	12,383	26,358	21,387
Total Proved Plus Probable	49,749	39,629	7,078	5,632	35,099	33,840	62,677	50,901

Notes:

(1)	Gross reserves are working interest reserves before royalty deductions.

(2)	Net reserves are working interest reserves after royalty deductions plus royalty interest reserves.

(3)	Natural Gas Liquids include Condensate volumes.

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Summary of Net Present Value of Future Net Revenue
Attributable to Oil and Gas Reserves (Forecast Prices and Costs)

As of March 1, 2021

	NET PRESENT VALUE OF FUTURE NET REVENUE DISCOUNTED AT (%/Year)
	Before Deducting Income Taxes
RESERVES CATEGORY	0%	5%	10%	15%	20%	Unit Value⁽¹⁾
	(in $ millions)					$/BOE
Proved Developed Producing	165	141	121	105	92	$10.21
Proved Undeveloped	161	105	67	42	24	$3.79
Total Proved	326	246	188	147	117	$6.37
Probable	346	205	127	83	56	$5.95
Total Proved Plus Probable	672	451	315	229	173	$6.19

Note:

(1)	Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes.

Forecast Prices and Costs

The forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of GLJ, McDaniel and Sproule as of January 1, 2021, and the following inflation and exchange rate assumptions:

								NATURAL GAS LIQUIDS
	CRUDE OIL					NATURAL GAS		Edmonton Par Price
Year		WTI⁽¹⁾	Edmonton Light⁽²⁾	Alberta Heavy⁽³⁾	Sask Cromer Medium⁽⁴⁾	Alberta AECO Spot Prices	U.S. Henry HubGas Price	Propane	Butanes	Condensate & Natural Gasoline	Inflation Rate	Exchange Rate
		($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMbtu)	($US/ MMbtu)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)	(%/year)	($US/$Cdn)
2021		47.17	55.76	39.87	53.77	2.78	2.83	18.18	26.36	59.24	0.0	0.768
2022		50.17	59.89	43.20	57.31	2.70	2.87	21.91	32.85	63.19	1.3	0.765
2023		53.17	63.48	46.86	60.68	2.61	2.90	24.57	39.20	67.34	2.0	0.763
2024		54.97	65.76	48.67	62.90	2.65	2.96	25.47	40.65	69.77	2.0	0.763
2025		56.07	67.13	49.65	64.22	2.70	3.02	26.00	41.50	71.18	2.0	0.763
2026		57.19	68.53	50.65	65.57	2.76	3.08	26.54	42.36	72.61	2.0	0.763
2027		58.34	69.95	51.67	66.94	2.81	3.14	27.09	43.24	74.07	2.0	0.763
2028		59.50	71.40	52.71	68.35	2.87	3.20	27.65	44.14	75.56	2.0	0.763
2029		60.69	72.88	53.76	69.78	2.92	3.26	28.23	45.06	77.08	2.0	0.763
2030		61.91	74.34	54.84	71.19	2.98	3.33	28.79	45.96	78.62	2.0	0.763
2031		63.15	75.83	55.94	72.61	3.04	3.39	29.37	46.88	80.20	2.0	0.763
2032		64.41	77.34	57.05	74.06	3.10	3.46	29.95	47.82	81.80	2.0	0.763
2033		65.70	78.89	58.20	75.55	3.16	3.53	30.55	48.77	83.44	2.0	0.763
2034		67.01	80.47	59.36	77.06	3.23	3.60	31.16	49.75	85.10	2.0	0.763
2035		68.35	82.08	60.55	78.60	3.29	3.67	31.79	50.74	86.81	2.0	0.763
Thereafter		⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	⁽⁵⁾	0.763

Notes:

(1)	West Texas Intermediate at Cushing Oklahoma 40^o API/0.5% sulphur.

(2)	Edmonton Light Sweet 40^o API/0.3% sulphur.

(3)	Heavy Crude Oil 12^o API at Hardisty, Alberta (after deducting blending costs to reach pipeline quality).

(4)	Midale Cromer Crude Oil 29^o API/2.0% sulphur.

(5)	Escalation is approximately 2% per year thereafter.

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Undiscounted Future Net Revenue by Resources Category

The undiscounted total future net revenue by reserves category as of March 1, 2021, using forecast prices and costs, is set forth below (columns or rows may not add due to rounding):

RESERVES CATEGORY	Revenue⁽¹⁾		Royalties⁽²⁾	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(in $ millions)
Proved Reserves	1,467	426		428	247	39	326

Proved Plus Probable Reserves	2,723	785		766	447	52	672

Notes:

(1)	Includes all product revenues and other revenues as forecast.

(2)	Royalties include any net profits interests paid.

Net Present Value of Future Net Revenue by Reserves Category and Product Type

The net present value of future net revenue before income taxes by reserves category and product type as of March 1, 2021, using forecast prices and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue Before Income Taxes
RESERVES CATEGORY	PRODUCT TYPE	(Discounted at 10%)	Unit Value⁽¹⁾
		(in $ thousands)	($/bbl; $/Mcf)
Proved Reserves	Tight Oil⁽²⁾	187,922	8.41
	Shale Gas⁽³⁾⁽⁴⁾	n/a	n/a
	Total	187,922
Proved Plus Probable Reserves	Tight Oil⁽²⁾	315,252	7.96
	Shale Gas⁽³⁾⁽⁴⁾	n/a	n/a
	Total	315,252

Notes:

(1)	Unit values are calculated using the 10% discounted rate divided by the major product type net reserves for each group, which is only comprised of tight oil.

(2)	Including net present value of solution gas and other by-products.

(3)	Including net present value of by-products, but excluding solution gas and by-products from oil wells.

(4)	No by-product oil or NGLs are associated with U.S. shale gas.

Estimated Production for Gross Reserves Estimates

The volume of total production associated with the Acquired Assets estimated for March 1, 2021 through December 31, 2021 in preparing the estimates of gross proved reserves and gross probable reserves is set forth below. Actual production may vary from the estimates below as the actual development programs, timing and priorities on the Acquired Assets conducted by the Corporation following closing of the Acquisition may differ from the forecast of development. Columns may not add due to rounding.

	Gross Proved Reserves		Gross Probable Reserves		Gross Proved and Probable Reserves
Product Type	Estimated 2021 Aggregate Production	Estimated 2021 Average Daily Production	Estimated 2021 Aggregate Production	Estimated 2021 Average Daily Production	Estimated 2021 Aggregate Production	Estimated 2021 Average Daily Production
Tight Oil	1,344 Mbbls	4,392 bbls/day	18 Mbbls	58 bbls/day	1,362 Mbbls	4,450 bbls/day
Total Crude Oil	1,344 Mbbls	4,392 bbls/day	18 Mbbls	58 bbls/day	1,362 Mbbls	4,450 bbls/day
Natural Gas Liquids	197 Mbbls	643 bbls/day	2 Mbbls	8 bbls/day	199 Mbbls	651 bbls/day
Total Liquids	1,541 Mbbls	5,035 bbls/day	20 Mbbls	66 bbls/day	1,561 Mbbls	5,101 bbls/day
Shale Gas	1,045 MMcf	3,416 Mcf/day	14 MMcf	46 Mcf/day	1,059 MMcf	3,462 Mcf/day
Total	1,715 MBOE	5,604 BOE/day	22 MBOE	73 BOE/day	1,737 MBOE	5,678 BOE/day

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Future Development Costs

The amount of development costs deducted in the estimation of net present value of future net revenue is set forth below. The Corporation intends to fund its development activities through cash, internally generated cash flow and/or debt. The Corporation does not anticipate that the cost of obtaining the funds required for these development activities will have a material effect on the Corporation's disclosed oil and gas reserves or future net revenue attributable to those reserves.

	Proved Reserves		Proved Plus Probable Reserves
Year	Undiscounted (M$)	Discounted at 10%/year (M$)	Undiscounted (M$)	Discounted at 10%/year (M$)

2021	3,780	3,624	3,780	3,624
2022	68,621	59,810	68,621	59,810
2023	84,202	67,351	84,202	67,351
2024	77,864	56,923	84,294	61,429
2025	12,124	8,232	102,110	67,401
2026	716	442	84,178	50,545
Remainder	-	-	20,106	11,244
Total	247,307	196,382	447,292	321,403

Significant Factors or Uncertainties

Changes in future commodity prices relative to the forecasts described above under "Forecast Prices and Costs" could have a negative impact on reserves and, in particular, on the development of undeveloped reserves associated with the Acquired Assets, unless future development costs are adjusted in parallel. Other than the foregoing and the factors disclosed or described in the tables above, the Corporation does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of reserves data associated with the Acquired Assets.

In connection with its operations, the Corporation will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines, including on properties associated with the Acquired Assets. The Corporation budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. There are no unusually significant abandonment and reclamation costs associated with reserves properties or properties with no attributed reserves associated with the Acquired Assets, and the Corporation does not anticipate its abandonment and reclamation liabilities to negatively impact reserves data associated with the Acquired Assets or its ability to develop these reserves at this time.

Marketing Arrangement and Forward Contracts

Crude oil production associated with the Acquired Assets is marketed to various buyers using a mix of negotiated contracts. Crude oil production associated with the Acquired Assets is transported to buyers by pipeline and/or truck. At times, a portion of such North Dakota crude oil production may be transported to the U.S. Gulf Coast, where it can further access export crude oil markets. NGLs associated with crude oil production volumes are marketed by midstream companies in North Dakota.

All of the natural gas production associated with the Acquired Assets was shale gas production from tight oil operations in North Dakota. These volumes are not marketed directly, as they are marketed by midstream companies in North Dakota.

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Presentation of Information in this Material Change Report

Information about the Acquired Assets

As the Corporation does not currently own the Acquired Assets, the information in this material change report relating to the Acquired Assets, has been summarized from information obtained from the Vendor and its affiliates. None of the Vendor or any of its affiliates or their respective directors, officers, employees, shareholders, members, partners, agents or other representatives (each, a "Vendor Party") makes any representation or warranty as to the accuracy or completeness of the information regarding the Acquired Assets or the Vendor contained in this material change report, and no Vendor Party was involved in the preparation or assembly of this material change report. No Vendor Party assumes any responsibility or liability for any errors or omissions in, or for any damages resulting from the use of, or any reliance on, any part of the information contained in this material change report.

The McDaniel Report on the Acquired Assets effective March 1, 2021 was prepared on behalf of the Corporation with information provided by the Corporation and other industry information available to McDaniel, and no Vendor Party participated in or provided any information to McDaniel in respect of such report.

General

Unless otherwise stated, all of the reserves information contained in this material change report has been prepared and presented in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulatory authorities, and the reserves definitions contained in the Canadian Securities Administrators Staff Notice 51-324. Unless otherwise stated, all of the reserves information in this material change report is on "gross" basis, which are working interest share before deduction of royalties and without including any royalty interests. Unless otherwise stated, all of the production information in this material change report is on a "company interest" basis, which are working interest share before deduction of royalties and including any royalty interests. Additionally, the oil and gas production volumes associated with the Acquired Assets that were made available to Enerplus were determined on a net basis, consistent with U.S. disclosure requirements and industry practice, and the Corporation has estimated company interest production volumes based on royalty and other information available to it.

The Corporation's actual oil and natural gas reserves and future production, including following completion of the Acquisition, may be greater than or less than the estimates provided in this material change report. The estimated future net revenue from the production of such oil and natural gas reserves does not necessarily represent the fair market value of such reserves.

Barrels of Oil Equivalent

The Corporation has adopted the standard of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to barrels of oil equivalent. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of six to one, utilizing a conversion on a six to one basis may be misleading as an indication of value.

API	American Petroleum Institute gravity, a measure of how heavy or light a petroleum liquid is compared to water
bbls/day	barrels (with each barrel representing 34.972 imperial gallons or 42 U.S. gallons) per day
Bcf	billion cubic feet
BOE	barrels of oil equivalent
BOE/day	barrels of oil equivalent per day
Mbbls	one thousand barrels
MBOE	one thousand barrels of oil equivalent
Mcf	one thousand cubic feet
Mcf/day	one thousand cubic feet per day
MMbbls	one million barrels
MMBOE	one million barrels of oil equivalent
MMbtu	one million British Thermal Units
MMcf	one million cubic feet
NGLs	natural gas liquids
WTI	West Texas Intermediate