PACIFIC EXPLORATION AND PRODUCTION CORP TORONTO, March 15, 2017 /PRNewswire/ - Pacific Exploration & Production Corporation (TSX: PEN) ("Pacific" or the "Company") announced today the release of its consolidated financial statements for the year and quarter ended December 31, 2016, together with its management discussion and analysis ("MD&A"), Annual Information Form ("AIF") and Form 51-101 F1 - Statement of Reserves Data and Other Oil and Gas Information for the Company (the "F1 Report") in respect of the year ended December 31, 2016. These documents, among others, will be posted on the Company's website at www.pacific.energy and SEDAR at www.sedar.com. All values in this news release and the Company's financial disclosures are in United States dollars unless otherwise stated.
Gabriel de Alba, Chairman of the Board of Directors, commented:
"The past year was one of significant change for Pacific, financially, operationally and culturally. The Company emerged from its restructuring with a new Board of Directors and management team and a plan focused on capital discipline and value maximization. We were able to deliver stable results through the end of 2016 and are now starting to see positive momentum in our core E&P efforts during the first two months of 2017. Combined with an ongoing review of assets and a targeted cost reduction program, we believe that we can continue to expand on this positive performance."
Barry Larson, Chief Executive Officer of the Company, commented:
"While 2016 results were primarily impacted by the expiration of the Rubiales and Piriri fields mid-year and lower drilling activity as a result of reduced capital expenditures during the Company's significant and successful restructuring process, I am very pleased with the amount of progress made on our plan to reduce costs, rationalize our portfolio and allow for a dedicated focus on high return opportunities on our core E&P assets in Colombia and Peru. We have a significant opportunity to create future growth and with capital discipline and operational rigor, we will take every step to create long-term value for our shareholders."
Full Year and Fourth Quarter 2016 Results
Operational Results:
-- For 2016, the Company's average daily net production after royalties was
103,532 boe/d, 33% lower compared with the previous year.
-- Fourth quarter 2016 average daily net production after royalties
decreased to 69,432 boe/d, lower by 57% as compared to the same period
of 2015.
-- The decrease in production was mainly attributable to the expiration of
the Rubiales-Piriri contract on June 30, 2016, and lower production in
other fields due to lower drilling activity and fourth quarter
operational issues related to water disposal capacity.
-- During 2016, the combined oil and gas operating cost was $22.78/boe,
slightly higher compared with $22.48/boe for 2015 due to higher
production and transportation costs but ameliorated by lower dilution
costs. Average production cost was higher due to lower volume produced,
and transportation cost rose as a result of slightly higher tariffs on
the main pipelines. Dilution cost was lower because of the Company's
strategy to utilize alternative dilution arrangements.
-- In 2016 the Company entered into several operational collaborative
agreements with third parties in Colombia which resulted in savings in
dilution cost and fuel cost.
Financial Results:
-- Revenue decreased to $1,412 million from $2,825 million in 2015, and for
the fourth quarter of 2016 to $270 million from $652 million for the
same period in 2015.
-- Operating EBITDA was $445 million for 2016 and $44 million for the
fourth quarter of 2016, lower compared to $1,166 million in 2015 and
$235 million in the fourth quarter of 2015.
-- The decreases in revenue and operating EBITDA were due to the nearly 16%
year-on-year decline in realized crude oil prices, the expiration of the
Rubiales-Piriri contract and $138 million lower realized gains from oil
hedging contracts compared with 2015.
-- Total volume of oil and gas sales (including trading) for the year 2016
averaged 95,496 boe/d, 40% lower than the 159,113 boe/d in 2015 mainly
due to the expiration of the Rubiales-Piriri fields in June 2016 and the
lower production in other fields due to lower drilling activity as a
result of reduced capital expenditures during the Company's
restructuring process.
-- Oil and gas operating netback for 2016 was $17.58/boe, 32% or $8.45
lower than the previous year. In 2016, combined realized price declined
by $8.15 compared to the previous year indicating that 96% of the
decline in combined operating netback in 2016 was attributable to the
decline in global crude prices.
-- The Company's average sales price per barrel of crude oil and natural
gas was $40.36/boe in 2016, down from $48.51/boe in 2015. Operating
netback in the fourth quarter of 2016 decreased to $13.94/boe from
$19.21/boe in the same period of 2015 due to lower volumes sold.
-- General and Administrative ("G&A") costs (excluding restructuring and
severance expenses) decreased to $145 million in 2016 and $40 million in
the fourth quarter of 2016 from $203 million in 2015 and $55 million in
the fourth quarter of 2015; the Company continues to reduce G&A and all
non-essential spending activities.
-- Net Income for 2016 was $2,449 million, largely due to non-cash items
and one-time items, including the recognition of a net gain of $3.6
billion on the cancellation of the debt held by the Affected Creditors
in exchange for the issuance of new common shares and $155 million in
costs related to the Restructuring Transaction.
-- The Company recorded net impairment charges of $477 million for 2016,
which included impairment losses of $1,114 million during the first
three quarters and a reversal of impairment of $637 million in the
fourth quarter of the year. Impairment tests were performed at the end
of 2016 based on the reserves certified by external evaluators as of
December 31, 2016.
-- Total capital expenditures decreased to $161 million in 2016 compared
with $726 million in 2015 as the Company focused on preserving cash
through the restructuring process.
Additional Highlights:
-- The Company continues to negotiate field commitments to focus on
high-impact development drilling. On March 17, 2016, the Agencia
Nacional de Hidrocarburos ("ANH") approved the transfer of $38 million
in exploration commitments from Las Aguilas, Castor, LL-59, LL-15 and
CPE-1 blocks to the Casanare Este, Mapache, Guatiquia, Guama LL-83 and
Rio Ariari blocks. On November 22, 2016, the ANH approved a second
investment transfer totaling $19 million from the CPO 14, Sabanero,
LL-19 and Topoyaco blocks to the LL-25 Block.
-- The Company successfully completed the divestment of all non-core assets
in Brazil. On September 27, 2016, the Company reached an agreement with
partners Karoon Gas Australia Ltd. and Karoon Petroleo e Gas Ltda.
(collectively, "Karoon"), to sell the Company's 35% working interest in
the joint concession agreements in Brazil for $15.5 million in cash
consideration. The transaction was approved by the Brazilian regulator
on January 31, 2017.
-- On October 14, 2016, the Company also reached an agreement with partner
Queiroz Galvão Exploração e Produção S.A. ("Queiroz") to withdraw
from joint working interests; the Company will pay $10 million in
exchange for release from future work commitments in the aggregate
amount of $76.3 million. The Queiroz transaction was approved by the
Brazilian regulator on March 13, 2017, and is expected to be fully
consummated shortly subject to the amendment of the concession
agreements. Also as a result of the transaction, the Company will be
released from approximately $41 million of letter of credit
requirements.
-- On November 30, 2016 the Company and Compañía Española de Petróleos
("CEPSA") Peru entered into an agreement, whereby CEPSA agreed to
acquire our 30% participating interest in the Licence Agreement for
Block 131, in which CEPSA Peru is the operator. The sale price is $17.8
million with adjustment based on future cash flow from the block; the
transaction is subject to Peruvian regulatory approval.
Financial Results:
Financial Summary
=================
Year Ended Three Months
December 31 Ended December 31
----------- -----------------
2016 2015 2016 2015
---- ---- ---- ----
Oil & Gas Sales Revenues ($ millions) 1,411.7 2,824.5 269.8 652.0
------------------------------------ ------- ------- ----- -----
Operating EBITDA ($ thousands)(1) 444,637 1,165,758 44,275 224,911
-------------------------------- ------- --------- ------ -------
Operating EBITDA Margin (Operating EBITDA/Revenues) 31% 37% 16% 34%
--------------------------------------------------- --- --- --- ---
Consolidated EBITDA ($ thousands)(1) 253,619 1,111,566 (1,967) 257,584
----------------------------------- ------- --------- ------ -------
Consolidated EBITDA Margin (Consolidated EBITDA/Revenues) 18% 39% (1)% 40%
--------------------------------------------------------- --- --- --- ---
Net income (Loss)(3) 2,448,523 (5,461,859) 4,025,194 (3,895,908)
------------------- --------- ---------- --------- ----------
Per share - basic ($)(2) 48.97 (1,733,923) 80.50 (1,236,713)
----------------------- ----- ---------- ----- ----------
Net Production (boe/d) 103,532 154,472 69,432 159,831
---------------------- ------- ------- ------ -------
Sales Volumes (boe/d) 95,496 159,113 69,653 171,928
--------------------- ------ ------- ------ -------
(COP$ / US$) Exchange Rate4 3,000.71 3,149.47 3,000.71 3,149.47
--------------------------- -------- -------- -------- --------
Average Shares Outstanding - basic (thousands) 50,002.4 3.2 50,002.4 3.2
============================================= ======== === ======== ===
(1) These metrics are Non-GAAP
financial measures. See below
Advisories "Non-GAAP Financial
Measure" and "Non-GAAP
Measures on page 20" in the
MD&A.
(2) The basic weighted average
numbers of common shares for
the years ended December 31,
2016 and 2015 were 50,002,363
and 3,150, respectively.
(3) Net Income (loss) attributable
to equity holders of the
parent.
4 COP/USD exchange rate
fluctuations can have a
significant impact on the
Company's accounting net
earnings, in the form of
unrealized foreign currency
translation on the Company's
financial assets and
liabilities and deferred tax
balances that are denominated
in COP.
Production:
Net Production Summary
======================
Year Ended Three Months
Ended
December 31 December 31
----------- -----------
2016 2015 2016 2015
---- ---- ---- ----
Oil (bbl/d)
-----------
Colombia 91,663 139,659 60,150 138,906
-------- ------ ------- ------ -------
Peru 3,106 5,586 2,079 10,462
---- ----- ----- ----- ------
Total Oil (bbl/d) 94,769 145,245 62,229 149,368
----------------- ------ ------- ------ -------
Natural Gas (boe/d)
-------------------
Colombia 8,763 9,227 7,203 10,463
-------- ----- ----- ----- ------
Total Natural Gas (boe/d) 8,763 9,227 7,203 10,463
------------------------- ----- ----- ----- ------
Total Equivalent Production (boe/d) 103,532 154,472 69,432 159,831
=================================== ======= ======= ====== =======
During 2016, net production after royalties and internal consumption totaled 103,532 boe/d, representing a decrease of 51,120 boe/d (33%) from the average net production of 154,472 boe/d reported in the previous year. This reduction is mainly attributable to the expiration of the Rubiales and Piriri fields, both of which were returned to Ecopetrol on June 30, 2016. Additionally, heavy oil production from Quifa SW and other fields decreased by 16% in comparison to 2015, mainly due to lower drilling activity and operational issues with water disposal capacity mainly due to temporary pump failures.
Light and medium net oil production in Colombia and Peru totaled 42,713 bbl/d, decreasing by 25% compared with 2015. The overall decrease was primarily due to lower drilling activity as a result of reduced capital expenditures during the Company's restructuring process in 2016. Light and medium oil and heavy oil production (excluding production at the Rubiales field) now represent 41% and 27%, respectively, of total net oil and gas production. Additionally, gas production decreased by 5% compared with the year 2015 due to reservoir water encroachment issues, and as of December 31, 2016 represented 8% of the total production.
2016 Reserves:
For the year ended December 31, 2016, the Company received independent certified reserves evaluation reports for all of its assets with total net 2P reserves of 170.7 MMboe. Compared with 290.8 MMboe certified for the year ended 2015, the year-over-year decline is mainly due to production for the year, the lower oil price forecasts resulting in economic revisions and the impact of technical revisions as assessed by the Company's independent reserves evaluators. Proved net reserves of 117.3 MMboe now represent 69% of the total 2P reserves compared with 68% of the total 2P reserves in 2015.
The following tables summarize information contained in the independent-reserves reports prepared by RPS Energy Canada Ltd. ("RPS") and Degolyer and MacNaughton ("D&M") effective December 31, 2016.
These reserves reports were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and the National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and included in the F1 Report filed on SEDAR. Additional reserves information as required under NI 51-101 can also be found on SEDAR, under the: (i) Forms 51-101F2 - Report on Reserves Data by Independent Qualified Reserves Evaluator completed by each of RPS and D&M dated February 27, 2017; and (ii) Form 51-101F3 - Report of Management and Directors on Oil and Gas Disclosure dated March 15, 2017.
All reserves presented are based on forecast pricing and estimated costs effective December 31, 2016 as determined by the Company's independent reserves evaluators. The Company's net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2016.
Reserves at December 31, 2016 (MMboe(1))
=======================================
Country Field Total Proved Probable (P2) Proved Plus Probable Hydrocarbon Type
(P1) (2P)
--- --- ---
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Colombia Quifa SW 47.2 41.3 3.5 3.0 50.7 44.3 Heavy Oil
--------
Other Heavy Oil Blocks(2) 32.5 28.1 14.5 12.2 47.0 40.3 Heavy Oil
Light/Medium Oil Blocks 38.8 35.7 28.0 25.7 66.8 61.4 Light & Medium Oil &
Associated Natural Gas
Natural Gas Blocks(3) 6.7 6.7 7.9 7.9 14.6 14.6 Natural Gas
-------------------- --- --- --- --- ---- ---- -----------
Sub-total 125.3 111.8 53.8 48.7 179.1 160.5 Oil & Natural Gas
--------- ----- ----- ---- ---- ----- ----- -----------------
Peru Light/Medium Oil & Natural Gas4 6.5 5.5 4.7 4.7 11.2 10.2 Oil & Natural Gas
---- ------------------------------- --- --- --- --- ---- ---- -----------------
Total at Dec. 31, 2016 131.8 117.3 58.5 53.4 190.3 170.7 Oil & Natural Gas
---------------------- ----- ----- ---- ---- ----- ----- -----------------
Total at Dec. 31, 2015 216.6 197.8 101.2 93.0 317.8 290.8
---------------------- ----- ----- ----- ---- ----- -----
Difference (84.8) (80.5) (42.7) (39.6) (127.5) (120.1)
---------- ----- ----- ----- ----- ------ ------
2016 Production 41.9 37.9 Total Reserves (85.6) (82.2)
Incorporated
=== ============
Notes:
1 See "Boe Conversion" section in
the Advisories, at the end of
this news release.
2 Includes Cajua, Jaspe, Quifa
North, Sabanero, CPE-6 and
Rio Ariari properties.
3 Includes La Creciente Field.
4 Includes onshore Block 131,
Block 192 and offshore Block
Z1.
In the table above, Gross refers to WI
before royalties, Net refers to WI
after royalties; numbers in table may
not add due to rounding differences.
2016 2P Reserves Reconciliation
===============================
Oil Equivalent Oil Equivalent Net
Gross 2P Reserves 2P Reserves
(MMboe) (MMboe)
------ ------
December 31, 2015 317.8 290.8
----------------- ----- -----
Net Additions and Technical Revisions (38.3) (40.5)
------------------------------------- ----- -----
Economic Revisions (47.2) (41.6)
------------------ ----- -----
Production(1) (41.9) (37.9)
------------ ----- -----
December 31, 2016 190.3 170.7
================= ===== =====
Notes:
1 Production represents the
production for the twelve
month period ended December
31, 2016.
Note: Numbers in the table may not
add due to rounding differences.
Fourth Quarter and Year End 2016 Conference Call Details:
As previously disclosed, a conference call for investors and analysts is scheduled for Thursday, March 16, 2017 at 8:30 a.m. (Bogotá time) and 9:30 a.m. (Toronto time). Participants will include Gabriel de Alba, Chairman of the Board of Directors, Barry Larson, Chief Executive Officer, Camilo McAllister, Chief Financial Officer and select members of the senior management team.
A presentation will be available on the Company's website prior to the call, which can be accessed at www.pacific.energy.
Analysts and interested investors are invited to participate using the following dial-in numbers:
Participant Number (International/Local): (647) 427-7450
Participant Number (Toll free Colombia): 01-800-518-0661
Participant Number (Toll free North America): (888) 231-8191
Conference ID: 85651976
Webcast: http://www.pacific.energy/en/webcast
A replay of the conference call will be available until 10:59 p.m. (Bogotá time) and 11:59 p.m. (Toronto time), Thursday, March 30, 2017 and can be accessed using the following dial-in numbers:
Encore Toll Free Dial-
in Number: 1-855-859-2056
Local Dial-in-Number: (416)-849-0833
Encore ID: 85651976
About Pacific:
Pacific is a Canadian public company and a leading explorer and producer of natural gas and crude oil, with operations focused in Latin America. The Company has a diversified portfolio of assets with interests in more than 45 exploration and production blocks in various countries including Colombia, Peru and Belize. The Company's strategy is focused on sustainable growth in production & reserves and cash generation. Pacific is committed to conducting business safely, in a socially and environmentally responsible manner.
The Company's common shares trade on the Toronto Stock Exchange under the ticker symbol PEN.
Advisories:
Cautionary Note Concerning Forward-Looking Statements
This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration and development plans and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company's prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates or has investments as the result of the completion of the Company's comprehensive restructuring transaction or otherwise; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 14, 2017 filed on SEDAR at www.sedar.com. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.
In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this press release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.
Non-GAAP Financial Measures
This report contains the following financial terms that are not considered in IFRS: Operating and Consolidated EBITDA, and Operating, Consolidated and Cash Netback. These non-IFRS measures do not have any standardized meaning, and therefore are unlikely to be comparable to similar measures presented by other companies. These non-IFRS measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These financial measures are included because management uses this information to analyze operating performance and liquidity. They are different from those measures disclosed in prior periods, reflecting the Company's new strategic focus on operational efficiency and capital discipline.
Management believes that Netback is a useful measure to assess the net profit after all the costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performances expressed as profit per barrel.
-- Operating Netback represents realized price per barrel plus realized
gain or loss on financial derivatives, less production costs,
transportation cost and diluent cost, and shows how efficient the
Company is at extracting and selling its product.
-- Consolidated Netback represents Operating Netback plus the results from
corporate investments such as the Company's pipeline investments that
are in addition to oil and gas production and the take-or-pay tariffs
paid on disrupted pipelines.
-- Cash Netback represents Consolidated Netback less corporate cash
expenses (general and administrative expenses and cash finance costs).
Management believes that EBITDA is a common measure used to assess profitability before the impact of different financing methods, income taxes, depreciation and impairment of capital assets and amortization of intangible assets.
-- Operating EBITDA represents the operating results of the Company's
primary business, excluding the effects of capital structure, other
investments (infrastructure assets), non-cash items that depend on
accounting policy choices, and one-time items that are not expected to
recur.
-- Consolidated EBITDA excludes items of a nonrecurring nature (one-time
items), or that could make the period-over-period comparison of results
from operations less meaningful, but includes results from the Company's
other investments (infrastructure assets).
A reconciliation of Operating and Consolidated EBIDA to net earnings is as follows:
Year Ended Three Months Ended
December 31 December 31
=========== ===========
(in
thousands
of US$ ) 2016 2015 2016 2015
---------- ---- ---- ---- ----
Net income
(loss)(1) $2,448,523 $(5,461,859) $4,025,194 $(3,895,908)
Adjustments
Income tax
expense
(recovery) 36,175 (466,514) (2,778) (358,669)
Depletion,
depreciation
and
amortization 575,985 1,529,016 85,700 380,281
Impairment
and
exploration
expenses 477,005 4,907,209 (636,594) 3,890,229
Finance
costs 191,245 434,846 66,497 205,917
Net gain on
restructuring (3,620,481) - (3,620,481) -
Restructuring
and
severance
costs 154,855 18,311 55,034 7,870
Equity tax 26,901 39,149 - -
Other
(income)
expenses (25,967) 80,992 15,661 27,914
Foreign
exchange
unrealized
(gain) loss (10,622) 30,416 9,800 (50)
------------ ------- ------ ----- ---
Consolidated
EBITDA 253,619 1,111,566 (1,967) 257,584
------------ ------- --------- ------ -------
Loss (gain)
on risk
management 139,457 (129,474) 13,471 (61,553)
Share of
(gain) loss
of equity-
accounted
investees (62,840) (21,537) 4,253 (7,875)
Gain (loss)
attributable
to non-
controlling
interest 15,288 (21,112) 5,085 (20,265)
Share based
compensation
(gain) loss (7,775) (1,564) 728 (6,245)
Foreign
exchange
realized
loss 1,759 104,061 4,057 21,446
Fees paid on
suspended
pipeline
capacity 105,129 123,818 18,648 41,819
------------ ------- ------- ------ ------
Operating
EBITDA $444,637 $1,165,758 $44,275 $224,911
--------- -------- ---------- ------- --------
1. Net gain (loss) attributable to
equity holders of the parent
2016 2015
==== ====
(in thousands of US$ ) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
--------------------- --- --- --- --- --- --- --- ---
Financial and Operational results:
Operating EBITDA 44,275 89,846 120,452 190,064 224,911 331,974 335,235 273,638
Consolidated EBITDA (1,967) 37,689 126,083 91,814 257,584 414,550 196,592 242,840
Please see the Company's most recent Management's Discussion and Analysis, which is available at www.sedar.com for additional information about these financial measures.
Boe Conversion
The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 5.7 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The Company's natural gas reserves are contained in the La Creciente, Guama and other blocks in Colombia as well as in Block Z-1, Peru. For all natural gas reserves in Colombia, boe's have been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy, and for all natural gas reserves in Peru, boe's have been expressed using the Peruvian conversion standard of 5.626 Mcf: 1 bbl required by Perupetro S.A. If a conversion standard of 6.0 Mcf: 1 bbl was used for all of the Company's natural gas reserves, this would result in a reduction in the Company's net 1P and 2P reserves of approximately 4.9 and 6.9 MMboe, respectively.
Definitions
Bcf Billion cubic feet.
--- -------------------
Bcfe Billion cubic feet of natural
gas equivalent.
---- ------------------------------
bbl Barrel of oil.
--- --------------
bbl/d Barrel of oil per day.
----- ----------------------
boe Barrel of oil equivalent. Boe's
may be misleading,
particularly if used in
isolation. The
Colombian standard is a boe
conversion ratio of 5.7 Mcf:1
bbl and is based on an energy
equivalency conversion method
primarily applicable at the
burner tip and does not
represent a value equivalency
at the wellhead.
--- ------------------------------
boe/d Barrel of oil equivalent per
day.
----- -----------------------------
Mbbl Thousand barrels.
---- -----------------
Mboe Thousand barrels of oil
equivalent.
---- ------------------------
MMbbl Million barrels.
----- ----------------
MMboe Million barrels of oil
equivalent.
----- -----------------------
Mcf Thousand cubic feet.
--- --------------------
Million Tons One million tons of LNG
(Liquefied Natural Gas) is
equivalent to 48 Bcf or
LNG 1.36 billion m3 of natural gas.
--- -------------------------------
Net Production Company working interest
production after deduction of
royalties.
-------------- ------------------------------
Total Field 100% of total field production
before accounting for working
interest and
Production royalty deductions.
---------- -------------------
Gross Company working interest
production before deduction of
royalties.
Production
----------
WTI West Texas Intermediate Crude
Oil.
--- ------------------------------
SOURCE Pacific Exploration and Production Corporation
