e40vfza
U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
40-F/A
AMENDMENT NO. 2
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REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934. |
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þ |
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ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended: December 31, 2005
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Commission File Number: 1-31253 |
PENGROWTH ENERGY TRUST
(Exact name of Registrant as specified in its charter)
Alberta, Canada
(Province or other jurisdiction of incorporation or organization)
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1311
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None |
(Primary Standard Industrial
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(I.R.S. Employer |
Classification Code Number)
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Identification Number) |
Suite 2900,
240 4th Avenue S.W.
Calgary, Alberta Canada T2P 4H4
(403) 233-0224
(Address and telephone number of Registrants principal executive offices)
Vinson & Elkins L.L.P.
2300 First City Tower, 1001 Fannin
Houston, Texas 77002-6760
(713) 758-2222
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
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Name
of each exchange on which registered |
Trust Units
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New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act.
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
For Annual Reports indicate by check mark the information filed with this Form:
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þ Annual information form
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þ Audited annual financial statements |
Indicate the number of outstanding shares of each of the issuers classes of capital or common
stock as of the close of the period covered by the annual report:
Indicate by check mark whether the Registrant filing the information contained in this Form is
also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the
Securities Exchange Act of 1934 (the Exchange Act). If Yes is marked, please indicate the
filing number assigned to the Registrant in connection with such Rule.
Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section
13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to filing requirements for
the past 90 days.
EXPLANATORY NOTE
This Amendment No. 2 (this Amendment) to the Annual Report on Form 40-F filed on March 31,
2006 (the Original Filing) of Pengrowth Energy Trust (Pengrowth) for the fiscal year ended
December 31, 2005, is being filed for the purpose of amending Pengrowths Managements Discussion
and Analysis to include the Disclosure Controls and Procedures section, which was inadvertently
omitted from the Original Filing. In addition, we are including as exhibits certain currently
dated certifications of our Chief Executive Officer and Chief Financial Officer.
Other
than as expressly set forth above, this Form 40-F/A does not,
and does not purport to, update or restate the information in any
Item of the Original Filing or reflect any events that have occurred
after the Original Filing was filed. The filing of this Amendment
shall not be deemed an admission that the Original
Filing, when made, included any known, untrue statement of material fact or knowingly omitted to
state a material fact necessary to make a statement not misleading.
DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT
The
following documents have been filed as part of this Amendment on Form 40-F:
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Appendix |
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Documents |
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A*
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Pengrowth Energy Trust Annual Information Form for the year ended
December 31, 2005. |
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B
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Managements
Discussion and Analysis (Revised) (included on pages 54
through 80 of the Pengrowth Energy Trust 2005 Annual Report). |
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C*
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Consolidated Financial Statements of Pengrowth Energy Trust,
including note 20 thereof which includes a reconciliation of the
Consolidated Financial Statements to United States generally
accepted accounting principles. |
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D*
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Five Year Review Pengrowth Energy Trust Consolidated Financial
Results (included on pages 115 through 119 of the Pengrowth
Energy Trust 2005 Annual Report). |
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E*
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Corporate Governance (included on pages 48 through 53 of the
Pengrowth Energy Trust 2005 Annual Report). |
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F*
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Oil and Gas Producing Activities Prepared in Accordance with SFAS
No. 69 Disclosures about Oil and Gas Producing Activities. |
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G*
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Auditors
Report. |
* Previously filed.
- 2 -
EXHIBIT
LIST
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1.* |
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Consent of KPMG LLP |
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2.* |
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Consent of Gilbert Laustsen Jung Associates Ltd. |
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3. |
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Certification pursuant to Section 906 |
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4. |
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Certificate of CEO |
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5. |
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Certificate of CFO |
- 3 -
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all
of the requirements for filing this Amendment on Form 40-F and has duly caused this Annual Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
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Date: September 15, 2006 |
PENGROWTH ENERGY TRUST
by its Administrator
PENGROWTH CORPORATION
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By: |
/s/ James S. Kinnear |
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James S. Kinnear |
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Chairman, President and
Chief Executive Officer |
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MANAGEMENTS
DISCUSSION AND ANALYSIS (REVISED)
(INCLUDED ON PAGES 54 THROUGH 80 OF THE PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)
Managements
Discussion and Analysis (Revised)
The following discussion and analysis of financial results should be read in conjunction with
the audited consolidated financial statements for the year ended December 31, 2005 and is based on
information available to February 27, 2006.
Frequently Recurring Terms
For the purposes of this Managements Discussion and Analysis, we use certain frequently
recurring terms as follows: the Trust refers to Pengrowth Energy Trust, the Corporation refers
to Pengrowth Corporation, Pengrowth refers to the Trust and the Corporation on a consolidated
basis and the Manager refers to Pengrowth Management Limited.
Advisory Regarding Forward-Looking Statements
This Managements Discussion and Analysis contains forward-looking statements within the
meaning of securities laws, including the safe harbour provisions of the Ontario Securities Act
and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information
is often, but not always, identified by the use of words such as anticipate, believe, expect,
plan, intend, forecast, target, project, may, will, should, could, estimate,
predict or similar words suggesting future outcomes or language suggesting an outlook.
Forward-looking statements in this Managements Discussion and Analysis include, but are not
limited to, statements with respect to: reserves, average 2006 production, production additions
from Pengrowths 2006 development program, the impact on production of divestitures in 2006, total
operating expenses for 2006, 2006 operating expenses per boe, capital expenditures for 2006 and the
breakdown of such capital expenditures for drilling, facilities and maintenance, land and seismic
Historical Annual Compound Returns by Year
(%)
Note: Assumes reinvestment of distributions in the trust at month end.
* Weighted average of Class A trust units
(NYSE) and Class B trust units (TSX).
54
PENGROWTH ENERGY TRUST
acquisition
and re-completions, work-overs and CO2 pilot. Statements relating
to reserves are deemed to be forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions that the reserves described exist in the quantities
predicted or estimated and can profitably be produced in the future.
Forward-looking statements and information are based on Pengrowths current beliefs as well as
assumptions made by and information currently available to Pengrowth concerning anticipated
financial performance, business prospects, strategies and regulatory developments. Although
management considers these assumptions to be reasonable based on information currently available to
it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both
general and specific, and risks that predictions, forecasts, projections and other forward-looking
statements will not be achieved. We caution readers not to place undue reliance on these statements
as a number of important factors could cause the actual results to differ materially from the
beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in
such forward-looking statements. These factors include, but are not limited to: the volatility of
oil and gas prices; production and development costs and capital expenditures; the imprecision of
reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids;
Pengrowths ability to replace and expand oil and gas reserves; environmental claims and
liabilities; incorrect assessments of value when making acquisitions; increases in debt service
charges; the loss of key personnel; the marketability of production; defaults by third party
operators; unforeseen title defects; fluctuations in foreign currency and exchange rates;
inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax
laws; the failure to qualify as a mutual fund trust; and Pengrowths ability to access external
sources of debt and equity capital. Further information regarding these factors may be found under
the heading Business Risks herein and under Risk Factors in Pengrowths Annual Information Form
which will be available on SEDAR at www.sedar.com on or before March 31, 2006.
Pengrowth cautions that the foregoing list of factors that may affect future results is not
exhaustive. When relying on our forward-looking statements to make decisions with respect to
Pengrowth, investors and others should carefully consider the foregoing factors and other
uncertainties and potential events. Furthermore, the forward-looking statements contained in this
Managements Discussion and Analysis are
55
2005 ANNUAL REPORT
made as of the date of this Managements Discussion and Analysis and Pengrowth does not
undertake any obligation to up-date publicly or to revise any of the included forward-looking
statements, whether as a result of new information, future events or otherwise. The forward-looking
statements contained in this Managements Discussion and Analysis are expressly qualified by this
cautionary statement.
Critical Accounting Estimates
As discussed in Note 2 to the financial statements, the financial statements are prepared in
accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required to
make estimates and assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and revenues and expenses for the period then ended.
The amounts recorded for depletion, depreciation and amortization of injectants and the provision
for asset retirement obligations are based on estimates. The ceiling test calculation is based on
estimates of proved reserves, production rates, oil and natural gas prices, future costs and other
relevant assumptions. As required by National Instrument 51-101 (NI 51-101), Pengrowth uses
independent qualified reserve evaluators in the preparation of reserve evaluations. By their
nature, these estimates are subject to measurement uncertainty and changes in these estimates may
impact the consolidated financial statements of future periods.
Non-GAAP Financial Measures
This discussion and analysis refers to certain financial measures that are not determined in
accordance with GAAP in Canada or the United States. These measures do not have standardized
meanings and may not be comparable to similar measures presented by other trusts or corporations.
Measures such as distributable cash, distributable cash per trust unit, payout ratio and operating
netbacks do not have standardized meanings prescribed by GAAP. During the second quarter of 2005,
Pengrowths withholding practice and presentation of distributable cash changed. The impact of the
new practice is discussed in the Distributable Cash, Distributions and Taxability of Distributions
section of this report on pages 69 to 70, while the remaining non-GAAP measures are determined by
reference to our financial statements. We discuss these measures because we believe that they
facilitate the understanding of the results of our operations and financial position.
Conversion and Currency
When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth
uses the international standard of six thousand cubic feet (mcf) to one barrel of oil equivalent.
Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio
of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead. Production
volumes, revenues and reserves are reported on a company interest gross basis (before royalties) in
accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise
specified.
Year 2005 Overview
Pengrowth achieved record net income and cash generated from operations for 2005.
Robust commodity prices, a full year of production from the 2004 Murphy acquisition and additional
production from the Swan Hills Unit No.1 (Swan Hills) and Crispin Energy Inc. (Crispin)
acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, combined to have
a favorable impact on 2005 financial and operating results relative to 2004. Financial hedging
losses of $65.8 million on crude oil and natural gas offset some of the positive impact of the high
commodity prices during the year as did the three percent depreciation of the U.S. dollar relative
to the Canadian dollar.
56
PENGROWTH ENERGY TRUST
Highlights
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Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record net
income of $326 million, an increase of 112 percent over 2004. |
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Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an increase of
more than ten percent versus 2004. Fourth quarter production averaged 61,442 boe per day, an
increase of four percent over the previous quarter and seven percent over the comparable
period in 2004. |
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Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over
2004. Fourth quarter distributable cash increased 87 percent versus 2004 to $196 million, the
highest level of distributable cash generated in any quarter in Pengrowths history. |
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Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82
per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004. Pengrowths monthly
distribution was increased in December 2005 to an annualized rate of $3.00 per trust unit. |
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Pengrowths payout ratio to unitholders for the full year and fourth quarter of 2005 reached
record lows of 72 percent and 61 percent of cash generated from operations, respectively. |
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Pengrowths 2005 development expenditures were essentially fully funded through withholdings
from distributable cash. |
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During the year Pengrowth spent a combined total of $176 million on maintenance and
development projects ending the year with proved plus probable (P50) reserves of 219.4 million
barrels of oil equivalent (mmboe) compared to 218.6 mmboe at year end 2004. Pengrowths P50
reserves were replaced through the addition of 16.7 mmboe related to acquisitions and 8.6
mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions
were offset by production of 21.7 mmboe and divestitures of 2.8 mmboe. |
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Pengrowths average realized commodity price (after hedging) increased 28 percent to $53.02
per boe in 2005, from $41.33 in 2004. |
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Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus $24.51 per
boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52 per boe in
2004. |
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On February 28, 2005, Pengrowth acquired an additional 11.89 percent working interest in the
Swan Hills property for $87 million. This acquisition increased Pengrowths total interest in
the property to 22.34 percent. |
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On April 29, 2005, Pengrowth successfully completed the acquisition of all of the issued and
outstanding shares of Crispin adding approximately 1,900 boe per day of production to our
portfolio. |
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On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured
ten year notes. |
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As at December 31, 2005, Pengrowth had generated a combined three-year weighted average
compound total return of 36 percent per annum for Class A and Class B unitholders. |
57
2005 ANNUAL REPORT
Summary of Financial and Operating Results
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Three months ended December 31 |
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Twelve months ended December 31 |
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(thousands, except per unit amounts) |
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2005 |
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2004 |
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% Change |
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2005 |
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2004 |
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% Change |
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INCOME STATEMENT |
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|
|
|
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|
|
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Oil and gas sales |
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|
$ |
353,923 |
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|
$ |
223,183 |
(2) |
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|
59 |
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|
$ |
1,151,510 |
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|
|
$ |
815,751 |
(2) |
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|
41 |
|
Net income |
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|
$ |
116,663 |
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|
|
$ |
31,138 |
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|
|
275 |
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$ |
326,326 |
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|
|
$ |
153,745 |
|
|
|
112 |
|
Net income per trust unit |
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|
$ |
0.73 |
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|
|
$ |
0.23 |
|
|
|
217 |
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$ |
2.08 |
|
|
|
$ |
1.15 |
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|
|
81 |
|
Cash generated from operations |
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|
$ |
196,588 |
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|
|
$ |
93,287 |
|
|
|
111 |
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|
|
$ |
618,070 |
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|
|
$ |
404,167 |
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|
53 |
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Cash generated from operations
per trust unit |
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$ |
1.23 |
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$ |
0.68 |
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|
81 |
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$ |
3.93 |
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$ |
3.03 |
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|
30 |
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Distributable cash (1) |
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$ |
195,879 |
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$ |
104,958 |
(2) |
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|
87 |
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|
|
$ |
619,739 |
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$ |
401,178 |
(2) |
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54 |
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Distributable cash per trust unit (1) |
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|
$ |
1.23 |
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|
$ |
0.77 |
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|
|
60 |
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|
$ |
3.94 |
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|
|
$ |
3.01 |
|
|
|
31 |
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Distributions paid or declared |
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|
$ |
119,858 |
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|
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$ |
96,466 |
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|
|
24 |
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$ |
445,977 |
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|
|
$ |
363,061 |
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|
23 |
|
Distributions paid or
declared per trust unit |
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|
$ |
0.75 |
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$ |
0.69 |
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9 |
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$ |
2.82 |
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$ |
2.63 |
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7 |
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Weighted average number of
trust units outstanding |
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159,528 |
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|
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|
136,916 |
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17 |
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|
157,127 |
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|
|
|
133,395 |
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|
18 |
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BALANCE SHEET |
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Working capital |
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$ |
(112,205 |
) |
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|
$ |
(78,546 |
) |
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43 |
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Property, plant and equipment
and other assets |
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$ |
2,067,988 |
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$ |
1,989,288 |
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|
4 |
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Long term debt |
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|
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|
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|
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|
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$ |
368,089 |
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$ |
345,400 |
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|
|
7 |
|
Unitholders equity |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,475,996 |
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|
|
$ |
1,462,211 |
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|
|
1 |
|
Unitholders equity per trust unit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
9.23 |
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|
|
$ |
9.56 |
|
|
|
(3 |
) |
Number of trust units
outstanding at year end |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
159,864 |
|
|
|
|
152,973 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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DAILY PRODUCTION |
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (barrels) |
|
|
|
21,179 |
|
|
|
|
20,118 |
|
|
|
5 |
|
|
|
|
20,799 |
|
|
|
|
20,817 |
|
|
|
0 |
|
Heavy oil (barrels) |
|
|
|
5,410 |
|
|
|
|
5,819 |
|
|
|
(7 |
) |
|
|
|
5,623 |
|
|
|
|
3,558 |
|
|
|
58 |
|
Natural gas (mcf) |
|
|
|
168,862 |
|
|
|
|
156,621 |
|
|
|
8 |
|
|
|
|
161,056 |
|
|
|
|
144,277 |
|
|
|
12 |
|
Natural gas liquids (barrels) |
|
|
|
6,710 |
|
|
|
|
5,385 |
|
|
|
25 |
|
|
|
|
6,093 |
|
|
|
|
5,281 |
|
|
|
15 |
|
Total production (boe) |
|
|
|
61,442 |
|
|
|
|
57,425 |
|
|
|
7 |
|
|
|
|
59,357 |
|
|
|
|
53,702 |
|
|
|
10 |
|
Total production (mboe) |
|
|
|
5,653 |
|
|
|
|
5,283 |
|
|
|
7 |
|
|
|
|
21,665 |
|
|
|
|
19,655 |
|
|
|
10 |
|
|
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|
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|
PRODUCTION PROFILE |
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|
Crude oil |
|
|
|
34 |
% |
|
|
|
35 |
% |
|
|
|
|
|
|
|
35 |
% |
|
|
|
39 |
% |
|
|
|
|
Heavy oil |
|
|
|
9 |
% |
|
|
|
10 |
% |
|
|
|
|
|
|
|
10 |
% |
|
|
|
6 |
% |
|
|
|
|
Natural gas |
|
|
|
46 |
% |
|
|
|
46 |
% |
|
|
|
|
|
|
|
45 |
% |
|
|
|
45 |
% |
|
|
|
|
Natural gas liquids |
|
|
|
11 |
% |
|
|
|
9 |
% |
|
|
|
|
|
|
|
10 |
% |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
AVERAGE REALIZED PRICES |
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|
|
|
|
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|
(AFTER HEDGING) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per barrel) |
|
|
$ |
59.40 |
|
|
|
$ |
44.76 |
|
|
|
33 |
|
|
|
$ |
58.59 |
|
|
|
$ |
43.21 |
|
|
|
36 |
|
Heavy oil (per barrel) |
|
|
$ |
31.77 |
|
|
|
$ |
26.99 |
|
|
|
18 |
|
|
|
$ |
33.32 |
|
|
|
$ |
32.45 |
|
|
|
3 |
|
Natural gas (per mcf) |
|
|
$ |
11.97 |
|
|
|
$ |
7.02 |
|
|
|
71 |
|
|
|
$ |
8.76 |
|
|
|
$ |
6.80 |
|
|
|
29 |
|
Natural gas liquids (per barrel) |
|
|
$ |
58.46 |
|
|
|
$ |
48.04 |
|
|
|
22 |
|
|
|
$ |
54.22 |
|
|
|
$ |
42.21 |
|
|
|
28 |
|
Average realized price per boe |
|
|
$ |
62.55 |
|
|
|
$ |
42.08 |
(2) |
|
|
49 |
|
|
|
$ |
53.02 |
|
|
|
$ |
41.33 |
(2) |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED PLUS PROBABLE RESERVES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,684 |
|
|
|
|
94,066 |
|
|
|
5 |
|
Heavy oil (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,790 |
|
|
|
|
18,245 |
|
|
|
(13 |
) |
Natural gas (bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
516 |
|
|
|
|
521 |
|
|
|
(1 |
) |
Natural gas liquids (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,985 |
|
|
|
|
19,395 |
|
|
|
(2 |
) |
Total oil equivalent (mboe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
219,396 |
|
|
|
|
218,613 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) See the section entitled Non-GAAP Financial Measures |
|
(2)Restated to conform to presentation
adopted in the current year |
58
PENGROWTH ENERGY TRUST
Results of Operations
Production
Average daily production increased over ten percent in 2005 compared to 2004. The increase is
attributable primarily to the Murphy, Swan Hills and Crispin acquisitions and contributions from
ongoing development activities. At this time, Pengrowth is forecasting average 2006 production of
54,000 to 56,000 boe per day from existing assets. This estimate incorporates anticipated
production additions from planned 2006 development activities. Offsetting these additions are
previously disclosed divestitures of approximately 1,300 boe per day in the first quarter of 2006,
which have been excluded from the above estimate, including the divestment of approximately 1,000
boe per day related to the Monterey Exploration Ltd. (Monterey) transaction announced on January
12, 2006 and expected production declines from normal operations. The above estimate specifically
excludes the potential impact of any other future acquisitions or divestitures.
Daily Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light crude oil (bbls) (1) |
|
|
|
21,179 |
|
|
|
|
20,660 |
|
|
|
|
20,118 |
|
|
|
|
20,799 |
|
|
|
|
20,817 |
|
Heavy oil (bbls) (1) |
|
|
|
5,410 |
|
|
|
|
5,405 |
|
|
|
|
5,819 |
|
|
|
|
5,623 |
|
|
|
|
3,558 |
|
Natural gas (mcf) |
|
|
|
168,862 |
|
|
|
|
164,288 |
|
|
|
|
156,621 |
|
|
|
|
161,056 |
|
|
|
|
144,277 |
|
Natural gas liquids (bbls) (1) |
|
|
|
6,710 |
|
|
|
|
5,448 |
|
|
|
|
5,385 |
|
|
|
|
6,093 |
|
|
|
|
5,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total boe per day |
|
|
|
61,442 |
|
|
|
|
58,894 |
|
|
|
|
57,425 |
|
|
|
|
59,357 |
|
|
|
|
53,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) bbls refers to barrels |
Light crude oil production volumes remained relatively flat year-over-year due to the positive
impact of production related to the Swan Hills and Crispin acquisitions which largely offset
natural production declines. Improved miscible flood response at Judy Creek contributed to most of
the three percent increase in production in fourth quarter 2005 versus the third quarter of 2005.
Heavy oil production increased 58 percent year-over-year due to the inclusion of a full 12 months
of production volumes from properties acquired in the Murphy acquisition which closed on May 31,
2004. The seven percent decrease in production for the fourth quarter of 2005 compared to the
fourth quarter of 2004 is attributable to natural production declines.
Natural gas production increased 12 percent year-over-year. Additional production volumes from the
Murphy and Crispin acquisitions and ongoing development activities, particularly the Monogram
infill drilling program completed in the fourth quarter of 2004, combined to more than offset
natural production declines. The three percent increase in volumes in the fourth quarter of 2005
compared to the third quarter of 2005 is due largely to a 44 well drilling program at Princess
which was completed during the fourth quarter. Fourth quarter 2005 volumes were eight percent
higher than fourth quarter 2004 volumes primarily due to the Crispin acquisition, new wells at
Princess and Sable Offshore Energy Project (SOEP) and lower residue gas solvent demand at Judy
Creek allowing for increased sales.
Natural gas liquids (NGLs) production increased 15 percent year-over-year primarily due to the
timing and size of condensate sales from SOEP. Pengrowth received six shipments (two shipments in
the fourth quarter) from SOEP in 2005 compared to four shipments in the previous year.
59
2005 ANNUAL REPORT
Pricing and Commodity Price Hedging
The increase in U.S. based prices for North American crude oil and natural gas was partially
offset by the negative impact of the rising Canadian dollar relative to the U.S. dollar and hedging
losses.
Average Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Cdn$) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light crude oil (per bbl) |
|
|
|
67.00 |
|
|
|
|
74.37 |
|
|
|
|
55.24 |
|
|
|
|
65.47 |
|
|
|
|
50.72 |
|
after hedging |
|
|
|
59.40 |
|
|
|
|
63.95 |
|
|
|
|
44.76 |
|
|
|
|
58.59 |
|
|
|
|
43.21 |
|
Heavy oil (per bbl) |
|
|
|
31.77 |
|
|
|
|
47.74 |
|
|
|
|
26.99 |
|
|
|
|
33.32 |
|
|
|
|
32.45 |
|
Natural gas (per mcf) |
|
|
|
12.80 |
|
|
|
|
8.69 |
|
|
|
|
7.25 |
|
|
|
|
8.99 |
|
|
|
|
7.03 |
|
after hedging |
|
|
|
11.97 |
|
|
|
|
8.57 |
|
|
|
|
7.02 |
|
|
|
|
8.76 |
|
|
|
|
6.80 |
|
Natural gas liquids (per bbl) |
|
|
|
58.46 |
|
|
|
|
57.75 |
|
|
|
|
48.04 |
|
|
|
|
54.22 |
|
|
|
|
42.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total per boe |
|
|
|
67.43 |
|
|
|
|
60.06 |
|
|
|
|
46.38 |
(3) |
|
|
|
56.06 |
|
|
|
|
44.85 |
(3) |
after hedging |
|
|
|
62.55 |
|
|
|
|
56.07 |
|
|
|
|
42.08 |
(3) |
|
|
|
53.02 |
|
|
|
|
41.33 |
(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI oil (U.S. $ per bbl) |
|
|
|
60.05 |
|
|
|
|
63.31 |
|
|
|
|
48.27 |
|
|
|
|
56.70 |
|
|
|
|
41.47 |
|
AECO spot gas (Cdn
$ per gj) (1) |
|
|
|
11.08 |
|
|
|
|
7.75 |
|
|
|
|
6.72 |
|
|
|
|
8.04 |
|
|
|
|
6.44 |
|
NYMEX gas (U.S. $ per mmbtu)(2) |
|
|
|
12.97 |
|
|
|
|
8.49 |
|
|
|
|
7.11 |
|
|
|
|
8.62 |
|
|
|
|
6.16 |
|
Currency
(U.S. $/Cdn $) |
|
|
|
0.85 |
|
|
|
|
0.83 |
|
|
|
|
0.82 |
|
|
|
|
0.83 |
|
|
|
|
0.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) gj refers to gigajoules |
|
(2) mmbtu refers to millions of British thermal units |
|
(3) Prior years restated to conform to presentation adopted in current year |
As part of our financial management strategy, Pengrowth uses forward price swap and option
contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability
to monthly cash distributions and to partially secure returns on significant new acquisitions.
Hedging Losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
Light crude oil ($ million) |
|
|
|
14.8 |
|
|
|
|
19.8 |
|
|
|
|
19.4 |
|
|
|
|
52.2 |
|
|
|
|
57.2 |
|
Light crude oil ($ per bbl) |
|
|
|
7.60 |
|
|
|
|
10.42 |
|
|
|
|
10.48 |
|
|
|
|
6.88 |
|
|
|
|
7.51 |
|
Natural gas ($ million) |
|
|
|
12.9 |
|
|
|
|
1.8 |
|
|
|
|
3.3 |
|
|
|
|
13.6 |
|
|
|
|
11.9 |
|
Natural gas ($ per mcf) |
|
|
|
0.83 |
|
|
|
|
0.12 |
|
|
|
|
0.23 |
|
|
|
|
0.23 |
|
|
|
|
0.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined ($ million) |
|
|
|
27.7 |
|
|
|
|
21.6 |
|
|
|
|
22.7 |
|
|
|
|
65.8 |
|
|
|
|
69.1 |
|
Combined ($ per boe) |
|
|
|
4.88 |
|
|
|
|
3.99 |
|
|
|
|
4.30 |
|
|
|
|
3.04 |
|
|
|
|
3.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity price hedges in place at December 31, 2005 are provided in Note 17 to the financial
statements. As of February 27, 2006, Pengrowth has not entered into any additional contracts
subsequent to year end.
60
PENGROWTH ENERGY TRUST
In conjunction with the Murphy acquisition, Pengrowth assumed certain fixed price natural gas
sales contracts and firm pipeline demand charge contracts associated with the Murphy reserves.
Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at
an average remaining contract price of Cdn $2.31 per mmbtu. As required by GAAP, the fair value of
the natural gas sales contract was recognized as a liability based on the mark-to-market value at
May 31, 2004. The liability at December 31, 2005 of $18.2 million for the contracts will continue
to be drawn down and recognized in income as the contracts are settled. As this is a non-cash
component of income, it is not included in the calculation of distributable cash. At December 31,
2005, the mark-to-market value of the fixed price physical sales contract represented a potential
loss of $35.3 million.
Oil
and Gas Sales Contribution Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, |
|
|
% of |
|
|
|
Sep. 30, |
|
|
% of |
|
|
|
Dec. 31, |
|
|
% of |
|
|
|
Dec. 31, |
|
|
% of |
|
|
|
Dec. 31, |
|
|
% of |
|
Sales Revenue |
|
|
2005 |
|
|
total |
|
|
|
2005 |
|
|
total |
|
|
|
2004 |
|
|
total |
|
|
|
2005 |
|
|
total |
|
|
|
2004 |
|
|
total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
|
186.0 |
|
|
|
53 |
|
|
|
|
129.5 |
|
|
|
43 |
|
|
|
|
101.2 |
|
|
|
45 |
|
|
|
|
514.9 |
|
|
|
45 |
|
|
|
|
359.3 |
|
|
|
44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light crude oil |
|
|
|
115.7 |
|
|
|
33 |
|
|
|
|
121.6 |
|
|
|
40 |
|
|
|
|
82.8 |
|
|
|
37 |
|
|
|
|
444.8 |
|
|
|
39 |
|
|
|
|
329.2 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids |
|
|
|
36.1 |
|
|
|
10 |
|
|
|
|
28.9 |
|
|
|
9 |
|
|
|
|
23.8 |
|
|
|
11 |
|
|
|
|
120.6 |
|
|
|
10 |
|
|
|
|
81.6 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy oil |
|
|
|
15.8 |
|
|
|
4 |
|
|
|
|
23.7 |
|
|
|
8 |
|
|
|
|
14.5 |
|
|
|
7 |
|
|
|
|
68.4 |
|
|
|
6 |
|
|
|
|
42.3 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brokered sales/sulphur |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
0.8 |
|
|
|
|
|
|
|
|
0.9 |
|
|
|
|
|
|
|
|
2.8 |
|
|
|
|
|
|
|
|
3.4 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
|
353.9 |
|
|
|
|
|
|
|
|
304.5 |
|
|
|
|
|
|
|
|
223.2 |
|
|
|
|
|
|
|
|
1,151.5 |
|
|
|
|
|
|
|
|
815.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Sales Price and Volumes Analysis
The following table illustrates the effect of changes in prices and volumes on the components
of oil and gas sales, including the impact of hedging.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
Natural gas |
|
|
Light oil |
|
|
NGLs |
|
|
Heavy oil |
|
|
Other |
|
|
Total |
|
|
Year ended December 31, 2004 |
|
|
359.3 |
|
|
|
329.2 |
|
|
|
81.6 |
|
|
|
42.3 |
|
|
|
3.4 |
|
|
|
815.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of change in product prices |
|
|
115.3 |
|
|
|
112.0 |
|
|
|
26.7 |
|
|
|
1.8 |
|
|
|
|
|
|
|
255.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of change in sales volumes |
|
|
42.0 |
|
|
|
(1.4 |
) |
|
|
12.3 |
|
|
|
24.3 |
|
|
|
|
|
|
|
77.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of hedging losses |
|
|
(1.7 |
) |
|
|
5.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.6 |
) |
|
|
(0.6 |
) |
|
Year ended
December 31, 2005 |
|
|
514.9 |
|
|
|
444.8 |
|
|
|
120.6 |
|
|
|
68.4 |
|
|
|
2.8 |
|
|
|
1,151.5 |
|
|
61
2005 ANNUAL REPORT
Transportation Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light oil transportation |
|
|
|
0.5 |
|
|
|
|
0.6 |
|
|
|
|
0.4 |
|
|
|
|
2.2 |
|
|
|
|
1.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per bbl |
|
|
|
0.27 |
|
|
|
|
0.29 |
|
|
|
|
0.23 |
|
|
|
|
0.29 |
|
|
|
|
0.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
transportation |
|
|
|
1.8 |
|
|
|
|
1.4 |
|
|
|
|
2.0 |
|
|
|
|
5.7 |
|
|
|
|
6.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per mcf |
|
|
|
0.12 |
|
|
|
|
0.09 |
|
|
|
|
0.14 |
|
|
|
|
0.10 |
|
|
|
|
0.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pengrowth incurs transportation costs for its product once the product enters a feeder or main
pipeline to the title transfer point. The transportation cost is dependant upon industry rates and
distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has
the option to sell some of its natural gas directly to premium markets outside of Alberta by
incurring additional transportation costs. In 2005, Pengrowth sold most of its natural gas without
incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell
approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first
major trading point, requiring minimal transportation costs.
Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty expense |
|
|
|
68.0 |
|
|
|
|
57.4 |
|
|
|
|
49.1 |
|
|
|
|
213.9 |
|
|
|
|
160.4 |
|
$ per boe |
|
|
|
12.03 |
|
|
|
|
10.60 |
|
|
|
|
9.29 |
|
|
|
|
9.87 |
|
|
|
|
8.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties as
a percent of sales |
|
|
|
19.2 |
% |
|
|
|
18.9 |
% |
|
|
|
22.0 |
% |
|
|
|
18.6 |
% |
|
|
|
19.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties include crown, freehold and overriding royalties as well as mineral taxes. A lesser
credit for enhanced oil recovery relief at Judy Creek had an unfavorable impact to royalties in the
fourth quarter of 2004 as solvent injection costs were lower than anticipated.
Processing, Interest and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing,
interest & other
income |
|
|
|
4.0 |
|
|
|
|
2.1 |
|
|
|
|
4.5 |
|
|
|
|
17.7 |
|
|
|
|
14.2 |
|
$ per boe |
|
|
|
0.71 |
|
|
|
|
0.39 |
|
|
|
|
0.83 |
|
|
|
|
0.82 |
|
|
|
|
0.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income is primarily derived from fees charged for processing
and gathering third party gas, road use, and oil and water processing. This income represents the
partial recovery of operating expenses included below in Operating Expenses.
62
PENGROWTH ENERGY TRUST
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
61.2 |
|
|
|
|
57.4 |
|
|
|
|
42.6 |
|
|
|
|
218.1 |
|
|
|
|
159.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe |
|
|
|
10.83 |
|
|
|
|
10.59 |
|
|
|
|
8.06 |
|
|
|
|
10.07 |
|
|
|
|
8.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses increased year-over-year as a result of timing of acquisitions partway
through 2004 and in 2005 which impacted costs by approximately $30 million. Additionally, there was
general pressure on goods and services in the oil and gas industry during 2005, with year-over-year
increases of more than ten percent within most of these areas. Utility costs also increased
approximately $10 million year-over-year. Operating expenses include costs incurred to earn
processing and other income reported above in Processing, Interest and Other Income.
Amortization of Injectants for Miscible Floods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased and capitalized |
|
|
|
14.5 |
|
|
|
|
6.9 |
|
|
|
|
8.2 |
|
|
|
|
34.7 |
|
|
|
|
20.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization |
|
|
|
7.1 |
|
|
|
|
6.0 |
|
|
|
|
4.9 |
|
|
|
|
24.4 |
|
|
|
|
19.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible
flood programs is amortized over the period of expected future economic benefit. Prior to 2005, the
expected future economic benefit from injection was estimated at 30 months, based on the results of
previous flood patterns. Commencing in 2005, the response period for additional new patterns being
developed is expected to be somewhat shorter relative to the historical miscible patterns in the
project. Accordingly, the cost of injectants purchased in 2005 will be amortized over a 24 month
period while costs incurred for the purchase of injectants in prior periods will continue to be
amortized over 30 months. As of December 31, 2005, the balance of unamortized injectant costs was
$35.3 million.
The value of Pengrowths proprietary injectants is not recorded until reproduced from the flood and
sold, although the cost of producing these injectants is included in operating expenses. Pengrowth
currently anticipates similar injection volumes for Judy Creek and increased injection volumes for
Swan Hills during 2006. This combined with higher forecast prices for natural gas and ethane is
anticipated to result in increased total injectant costs for 2006.
Interest
Interest expense decreased by 28 percent to $21.6 million in 2005 from $29.9 million in 2004,
reflecting a lower average debt level combined with lower standby fees. Standby fees in 2004 of
$3.9 million were related to the set-up of bridge financing utilized for the 2004 Murphy
acquisition. Imputed interest on the note payable to Emera Offshore Incorporated (Emera) was also
recorded in the amount of $1.3 million (2004 $1.6 million).
63
2005 ANNUAL REPORT
The average interest rate on Pengrowths long term debt outstanding at December 31, 2005 is
5.1 percent. Approximately 63 percent of Pengrowths outstanding debt as at December 31, 2005
incurs interest expense payable in U.S. dollars and therefore remains subject to fluctuations in
the U.S. dollar exchange rate. The note payable is non-interest bearing.
Foreign Currency Gains and Losses
Pengrowth recorded a net foreign exchange gain of $7.0 million in 2005, compared to a foreign
exchange gain of $17.3 million in 2004. Included in the 2005 gain is a $7.8 million unrealized
foreign exchange gain related to the U.S. dollar denominated debt. This gain arises as a result of
the increase in the Canadian to U.S. dollar exchange rate in 2005 from a rate of approximately
$0.83 at December 31, 2004 to a rate of approximately $0.86 at December 31, 2005. Offsetting this
gain is a realized foreign exchange loss of $0.8 million related mainly to U.S. dollar denominated
receivables. Revenues are recorded at the average exchange rate for the production month in which
they accrue, with payment being received on or about the 25th of the following month. As a result
of the increase in the Canadian dollar relative to the U.S. dollar over the course of the year, a
foreign exchange loss was recorded to the extent that there was a difference between the average
exchange rate for the month of production and the exchange rate at the date the payments were
received on that portion of production sales that are received in U.S. dollars. Pengrowth has
arranged a significant portion of its long term debt in U.S. dollars as a natural hedge against a
stronger Canadian dollar, as the negative impact on oil and gas sales is somewhat offset by a
reduction in the U.S. dollar denominated interest cost. (See Note 12 to the financial statements
for further detail).
General and Administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash G&A expense |
|
|
|
7.7 |
|
|
|
|
7.0 |
|
|
|
|
6.5 |
|
|
|
|
27.4 |
|
|
|
|
22.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe |
|
|
|
1.36 |
|
|
|
|
1.29 |
|
|
|
|
1.23 |
|
|
|
|
1.27 |
|
|
|
|
1.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash G&A expense |
|
|
|
0.8 |
|
|
|
|
0.6 |
|
|
|
|
0.4 |
|
|
|
|
2.9 |
|
|
|
|
2.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe |
|
|
|
0.14 |
|
|
|
|
0.11 |
|
|
|
|
0.08 |
|
|
|
|
0.13 |
|
|
|
|
0.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total G&A ($ million) |
|
|
|
8.5 |
|
|
|
|
7.6 |
|
|
|
|
6.9 |
|
|
|
|
30.3 |
|
|
|
|
24.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total G&A ($ per boe) |
|
|
|
1.50 |
|
|
|
|
1.40 |
|
|
|
|
1.31 |
|
|
|
|
1.40 |
|
|
|
|
1.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The cash component of General and Administrative (G&A) increased due to a number of factors
including the addition of personnel and office space in conjunction with the Murphy acquisition as
well as a general increase in expanded financial reporting, legal and regulatory costs from the
growth in our unitholder base and increasing regulatory requirements including preparing for
compliance with the Sarbanes-Oxley Act. The non-cash compensation expense is related to the value
of trust unit options and rights (see Note 2 and Note 10 to the financial statements for details).
Also included in 2005 G&A is $0.9 million (2004
$0.8 million) for estimated reimbursement of G&A expenses incurred by the Manager, pursuant to
the management agreement.
64
PENGROWTH ENERGY TRUST
Management Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ million) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Management Fee |
|
|
|
2.2 |
|
|
|
|
1.6 |
|
|
|
|
1.4 |
|
|
|
|
9.1 |
|
|
|
|
6.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Fee |
|
|
|
2.2 |
|
|
|
|
1.9 |
|
|
|
|
1.2 |
|
|
|
|
6.9 |
|
|
|
|
6.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ($ million) |
|
|
|
4.4 |
|
|
|
|
3.5 |
|
|
|
|
2.6 |
|
|
|
|
16.0 |
|
|
|
|
12.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total ($ per boe) |
|
|
|
0.77 |
|
|
|
|
0.65 |
|
|
|
|
0.48 |
|
|
|
|
0.74 |
|
|
|
|
0.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Under the current management agreement, which came into effect July 1, 2003 for two three-year
terms ending June 30, 2009, the Manager will earn a performance fee if the Trusts total returns
exceed eight percent per annum on a three year rolling average basis. At the end of the first term
a review process will determine whether to extend the agreement for the second term. The maximum
fees payable, including the performance fee, is limited to 80 percent of the fees that would
otherwise have been payable under the previous management agreement for the first three years and
60 percent for the subsequent three years.
The Trust achieved a three year average total return of 36 percent per annum at the end of 2005; as
a result the Manager earned the maximum fee payable under the new management agreement.
Related Party Transactions
Details of related party transactions incurred in 2005 and 2004 are provided in Note 15 to the
financial statements. These transactions include the management fees paid to the Manager. The
Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of
the Corporation. The management fees paid to the Manager are pursuant to a management agreement
which has been approved by the trust unitholders. Mr. Kinnear does not receive any salary or bonus
in his capacity as a director and officer of the Corporation and has not received any new trust
unit options or rights since November 2002.
Related
party transactions in 2005 also include $0.7 million (2004 $0.8 million) paid to a law
firm controlled by the Vice President and Corporate Secretary of Pengrowth Corporation, Charles V.
Selby. These fees are paid in respect of legal and advisory services provided by the Vice President
and Corporate Secretary. Mr. Selby does not receive any salary or bonus in his capacity as Vice
President and Corporate Secretary of the Corporation. Mr. Selby has from time to time been granted
trust unit rights and options.
Taxes
In determining its taxable income, the Corporation deducts payments made to the Trust,
effectively transferring the income tax liability to unitholders thus reducing taxable income to
nil. Under the Corporations current distribution policy, funds are withheld from distributable
cash to fund future capital expenditures and repay debt. As a result of increased amounts being
withheld to fund capital spending, the Corporation could become subject to taxation on a portion of
its income in the future. This can be mitigated through various options including the issuance of
additional trust units, increased tax pools from additional capital spending, modifications to the
distribution policy or changes to the corporate structure. As a result, the Corporation does not
anticipate the payment of any cash income taxes in the foreseeable future.
Capital taxes paid or payable by the Corporation, based on debt and equity levels at the end of the
year, amounted to $6.2 million in 2005 (2004 $4.6 million). This amount is comprised of Federal
Large Corporations Tax of $2.2 million (2004 $1.3 million) and Saskatchewan Capital Tax and
Resource Surcharge of $4.0 million (2004 $3.2 million). The increase in 2005 capital taxes is due
to a higher taxable capital base from the Crispin acquisition and increased capital expenditures
relative to 2004.
65
2005 ANNUAL REPORT
The corporate acquisition of Crispin in 2005 resulted in Pengrowth recording an additional
future tax liability of $22.2 million. A $75.6 million future tax liability was initially recorded
in 2004 as a result of the Murphy acquisition. The future tax liability represents the difference
between the tax basis and the fair values assigned to the acquired assets. A comparison of the fair
value and tax basis at the end of the year increased the future tax liability by $12.3 million to
$110.1 million.
Depletion, Depreciation and Accretion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and
Depreciation |
|
|
|
71.4 |
|
|
|
|
73.5 |
|
|
|
|
69.4 |
|
|
|
|
285.0 |
|
|
|
|
247.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe |
|
|
|
12.63 |
|
|
|
|
13.57 |
|
|
|
|
13.14 |
|
|
|
|
13.15 |
|
|
|
|
12.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion |
|
|
|
3.6 |
|
|
|
|
3.6 |
|
|
|
|
3.2 |
|
|
|
|
14.2 |
|
|
|
|
10.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe |
|
|
|
0.64 |
|
|
|
|
0.66 |
|
|
|
|
0.60 |
|
|
|
|
0.65 |
|
|
|
|
0.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion and depreciation of property, plant and equipment and other assets is provided on
the unit of production method based on total proved reserves. The provision for depletion and
depreciation increased 15 percent in 2005 due to a larger depletable asset base and a higher
depletion rate (production as a percentage of total proved reserves).
Accretion increased 34 percent year-over-year due to a larger Asset Retirement Obligation (ARO).
Ceiling Test
Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant
and equipment and other assets. The carrying value is assessed to be recoverable when the sum of
the undiscounted cash flows expected from the production of proved reserves, the lower of cost and
market of unproved properties and the cost of major development projects exceeds the carrying
value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized
to the extent that the carrying value of assets exceeds the sum of the discounted cash flows
expected from the production of proved and probable reserves, the lower of cost and market of
unproved properties and the cost of major development projects. The cash flows are estimated using
expected future product prices and costs and are discounted using a risk-free interest rate. There
was a significant surplus in the ceiling test at year end 2005.
Asset Retirement Obligations
The total future ARO were estimated by management based on estimated costs to remediate,
reclaim and abandon wells and facilities based on Pengrowths working interest and the estimated
timing of the costs to be incurred in future periods. Pengrowth has estimated the net present value
of its total ARO to be $185 million as at December 31, 2005
(2004 $172 million), based on a total
escalated future liability of $1,041 million (2004 $551 million). The significant change in the
estimated future liability is due to increasing regulatory requirements, changing the economic life
to agree with GLJ Petroleum Consultants Ltd. (GLJ) assumptions and increasing the future inflation
rate. These costs are expected to be incurred over 50 years with the majority of the costs incurred
between 2032 and 2054. Pengrowths credit adjusted risk free
rate of eight percent (2004 eight
percent) and an inflation rate of 2.0 percent (2004 1.5 percent) were used to calculate the net
present value of the ARO.
66
PENGROWTH ENERGY TRUST
Remediation Trust Funds & Remediation and Abandonment Expenses
During 2005, Pengrowth contributed $1.3 million into trust funds established to fund certain
abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these
remediation trust funds was $8.3 million at December 31, 2005.
Pengrowth takes a proactive approach to managing its well abandonment and site restoration
obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In
2005, Pengrowth spent $7.4 million on abandonment and
reclamation (2004 $4.4 million). Pengrowth
expects to spend approximately $11 million per year, prior to inflation, over the next ten years on
remediation and abandonment.
Goodwill
In accordance with Canadian GAAP, Pengrowth recorded goodwill of $12.2 million upon the
Crispin acquisition in 2005 and $170.6 million upon the Murphy acquisition in 2004. The goodwill
value was determined based on the excess of total consideration paid less the net value assigned to
other identifiable assets and liabilities, including the future income tax liability. Details of
the acquisitions are provided in Note 4 to the financial statements.
Netbacks
There is no standardized measure of operating netbacks and therefore operating netbacks, as
presented below may not be comparable to similar measures presented by other companies. Certain
assumptions have been made in allocating operating expenses, other production income, processing,
interest and other income and royalty injection credits between light crude oil, heavy oil, natural
gas and NGL production.
Pengrowth recorded an operating netback of $32.54 per boe (after hedging) in 2005 compared to
$24.51 (after hedging) in 2004, mainly due to higher average commodity prices in 2005 partially
offset by higher operating expenses and royalties.
Combined Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ per boe) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
|
|
62.55 |
|
|
|
|
56.07 |
|
|
|
|
42.08 |
|
|
|
|
53.02 |
|
|
|
|
41.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other production income |
|
|
|
0.06 |
|
|
|
|
0.13 |
|
|
|
|
0.17 |
|
|
|
|
0.13 |
|
|
|
|
0.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62.61 |
|
|
|
|
56.20 |
|
|
|
|
42.25 |
|
|
|
|
53.15 |
|
|
|
|
41.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income |
|
|
|
0.71 |
|
|
|
|
0.39 |
|
|
|
|
0.83 |
|
|
|
|
0.82 |
|
|
|
|
0.72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
(12.02 |
) |
|
|
|
(10.60 |
) |
|
|
|
(9.29 |
) |
|
|
|
(9.87 |
) |
|
|
|
(8.16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
(10.83 |
) |
|
|
|
(10.59 |
) |
|
|
|
(8.07 |
) |
|
|
|
(10.07 |
) |
|
|
|
(8.13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation costs |
|
|
|
(0.41 |
) |
|
|
|
(0.36 |
) |
|
|
|
(0.47 |
) |
|
|
|
(0.36 |
) |
|
|
|
(0.42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of injectants |
|
|
|
(1.25 |
) |
|
|
|
(1.10 |
) |
|
|
|
(0.94 |
) |
|
|
|
(1.13 |
) |
|
|
|
(1.00 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
|
38.81 |
|
|
|
|
33.94 |
|
|
|
|
24.31 |
|
|
|
|
32.54 |
|
|
|
|
24.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
2005 ANNUAL REPORT
Light Crude Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ per bbl) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
|
|
59.40 |
|
|
|
|
63.95 |
|
|
|
|
44.76 |
|
|
|
|
58.59 |
|
|
|
|
43.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other production income |
|
|
|
0.17 |
|
|
|
|
0.37 |
|
|
|
|
0.48 |
|
|
|
|
0.37 |
|
|
|
|
0.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59.57 |
|
|
|
|
64.32 |
|
|
|
|
45.24 |
|
|
|
|
58.96 |
|
|
|
|
43.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income |
|
|
|
0.34 |
|
|
|
|
0.64 |
|
|
|
|
0.51 |
|
|
|
|
0.47 |
|
|
|
|
0.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
(6.47 |
) |
|
|
|
(11.03 |
) |
|
|
|
(9.65 |
) |
|
|
|
(8.64 |
) |
|
|
|
(7.62 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
(14.32 |
) |
|
|
|
(12.85 |
) |
|
|
|
(9.17 |
) |
|
|
|
(12.28 |
) |
|
|
|
(9.31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation costs |
|
|
|
(0.27 |
) |
|
|
|
(0.29 |
) |
|
|
|
(0.23 |
) |
|
|
|
(0.29 |
) |
|
|
|
(0.23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of injectants |
|
|
|
(3.63 |
) |
|
|
|
(3.14 |
) |
|
|
|
(2.67 |
) |
|
|
|
(3.21 |
) |
|
|
|
(2.58 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
|
35.22 |
|
|
|
|
37.65 |
|
|
|
|
24.03 |
|
|
|
|
35.01 |
|
|
|
|
24.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ per bbl) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
|
|
31.77 |
|
|
|
|
47.74 |
|
|
|
|
26.99 |
|
|
|
|
33.32 |
|
|
|
|
32.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income |
|
|
|
0.74 |
|
|
|
|
(0.83 |
) |
|
|
|
|
|
|
|
|
0.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
(2.98 |
) |
|
|
|
(8.00 |
) |
|
|
|
(4.19 |
) |
|
|
|
(4.53 |
) |
|
|
|
(4.87 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
(11.60 |
) |
|
|
|
(16.30 |
) |
|
|
|
(9.44 |
) |
|
|
|
(15.65 |
) |
|
|
|
(9.85 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
|
17.93 |
|
|
|
|
22.61 |
|
|
|
|
13.36 |
|
|
|
|
13.50 |
|
|
|
|
17.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ per mcf) |
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
Dec. 31, 2005 |
|
|
|
Sep. 30, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
Dec. 31, 2005 |
|
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
|
|
11.97 |
|
|
|
|
8.57 |
|
|
|
|
7.02 |
|
|
|
|
8.76 |
|
|
|
|
6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income |
|
|
|
0.19 |
|
|
|
|
0.09 |
|
|
|
|
0.24 |
|
|
|
|
0.23 |
|
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
(2.62 |
) |
|
|
|
(1.47 |
) |
|
|
|
(1.34 |
) |
|
|
|
(1.70 |
) |
|
|
|
(1.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
(1.38 |
) |
|
|
|
(1.31 |
) |
|
|
|
(1.16 |
) |
|
|
|
(1.24 |
) |
|
|
|
(1.15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation costs |
|
|
|
(0.12 |
) |
|
|
|
(0.09 |
) |
|
|
|
(0.14 |
) |
|
|
|
(0.10 |
) |
|
|
|
(0.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
|
8.04 |
|
|
|
|
5.79 |
|
|
|
|
4.62 |
|
|
|
|
5.95 |
|
|
|
|
4.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68
PENGROWTH ENERGY TRUST
NGLs Netbacks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ per bbl) |
|
|
Three months ended |
|
|
Twelve months ended |
|
|
|
Dec. 31, 2005 |
|
|
Sep. 30, 2005 |
|
|
Dec. 31, 2004 |
|
|
Dec. 31, 2005 |
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
|
|
58.46 |
|
|
|
|
57.75 |
|
|
|
|
48.04 |
|
|
|
|
54.22 |
|
|
|
|
42.21 |
|
Royalties |
|
|
|
(21.29 |
) |
|
|
|
(20.57 |
) |
|
|
|
(19.37 |
) |
|
|
|
(17.66 |
) |
|
|
|
(15.43 |
) |
Operating expenses |
|
|
|
(10.05 |
) |
|
|
|
(10.13 |
) |
|
|
|
(7.87 |
) |
|
|
|
(9.04 |
) |
|
|
|
(7.94 |
) |
Transportation costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.10 |
) |
|
|
|
|
|
|
|
|
(0.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
|
27.12 |
|
|
|
|
27.05 |
|
|
|
|
20.70 |
|
|
|
|
27.52 |
|
|
|
|
18.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash, Distributions and Taxability of Distributions
Pengrowth generated $619.7 million ($3.94 per average trust unit outstanding) of distributable
cash from 2005 operations, compared to $401.2 million ($3.01 per unit) in 2004. Distributions paid
or declared were $446.0 million for 2005 (2004 $363.1 million) and as a percentage of cash
generated from operations (payout ratio) represent approximately 72 percent (2004 90 percent).
The Board of Directors may change the amount withheld in the future, depending on a number of
factors, including future commodity prices, capital expenditure requirements, and the availability
of debt and equity capital. Pursuant to the Royalty Indenture, the Board of Directors can establish
a reserve for certain items including up to 20 percent of Gross Revenue to fund future capital
expenditures or for the payment of royalty income in any future period.
Cash distributions are comprised of a return of capital portion, which is tax deferred, and return
on capital portion which is taxable income. The return of capital portion reduces the cost base of
a unitholders trust units for purposes of calculating a capital gain or loss upon ultimate
disposition. The following discussion relates to the taxation of Canadian unitholders only. For
detailed tax information relating to non-residents, please refer to our website www.pengrowth.com.
Cash distributions are paid to unitholders on the 15th day of the second month following the month
of production. Cash distributions paid in the 2005 calendar year totaled $2.78 per trust unit and
are 80 percent return on capital (taxable) or $2.22 per trust unit and 20 percent return of capital
(tax deferred) or $0.56 per trust unit. Changes in the estimated taxable and deferred portion of
the cash distributions are announced quarterly.
There is no standardized measure of distributable cash and therefore distributable cash, as
reported by Pengrowth, may not be comparable to similar measures presented by other trusts. In
conjunction with the change to Pengrowths withholding practice, distributable cash as presented
below may not be comparable to previous disclosures. The following table provides a reconciliation
of distributable cash.
69
2005 ANNUAL REPORT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except per trust unit amounts) |
|
|
Three
months ended |
|
|
Twelve
months ended |
|
|
|
Dec. 31, 2005 |
|
|
Sep. 30, 2005 |
|
|
Dec. 31, 2004 |
|
|
Dec. 31, 2005 |
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash generated from operations |
|
|
|
196,588 |
|
|
|
|
158,976 |
|
|
|
|
93,287 |
|
|
|
|
618,070 |
|
|
|
|
404,167 |
|
Change in non-cash
operating working capital |
|
|
|
(7,993 |
) |
|
|
|
(789 |
) |
|
|
|
8,576 |
|
|
|
|
(9,833 |
) |
|
|
|
(1,173 |
) |
Change in deferred injectants |
|
|
|
7,411 |
|
|
|
|
892 |
|
|
|
|
3,228 |
|
|
|
|
10,265 |
|
|
|
|
746 |
|
Change in remediation trust funds |
|
|
|
784 |
|
|
|
|
(272 |
) |
|
|
|
32 |
|
|
|
|
(20 |
) |
|
|
|
(917 |
) |
Change in deferred charges |
|
|
|
(793 |
) |
|
|
|
2,818 |
|
|
|
|
(473 |
) |
|
|
|
1,235 |
|
|
|
|
(1,893 |
) |
Other |
|
|
|
(118 |
) |
|
|
|
384 |
|
|
|
|
308 |
|
|
|
|
22 |
|
|
|
|
248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash |
|
|
|
195,879 |
|
|
|
|
162,009 |
|
|
|
|
104,958 |
|
|
|
|
619,739 |
|
|
|
|
401,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of Distributable Cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash withheld |
|
|
|
76,021 |
|
|
|
|
52,156 |
|
|
|
|
8,492 |
|
|
|
|
173,762 |
|
|
|
|
38,117 |
|
Distributions paid or declared |
|
|
|
119,858 |
|
|
|
|
109,853 |
|
|
|
|
96,466 |
|
|
|
|
445,977 |
|
|
|
|
363,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash |
|
|
|
195,879 |
|
|
|
|
162,009 |
|
|
|
|
104,958 |
|
|
|
|
619,739 |
|
|
|
|
401,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash per trust unit |
|
|
|
1.23 |
|
|
|
|
1.02 |
|
|
|
|
0.77 |
|
|
|
|
3.94 |
|
|
|
|
3.01 |
|
Distributions paid or
declared per trust unit |
|
|
|
0.75 |
|
|
|
|
0.69 |
|
|
|
|
0.69 |
|
|
|
|
2.82 |
|
|
|
|
2.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payout ratio(1) |
|
|
|
61 |
% |
|
|
|
69 |
% |
|
|
|
103 |
% |
|
|
|
72 |
% |
|
|
|
90 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Payout ratio is calculated as distributions paid or declared divided by cash
generated from operations. |
At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2006 distributions
will be taxable to Canadian residents. This estimate is subject to change depending on a number of
factors including, but not limited to, the level of commodity prices, acquisitions, dispositions,
and new equity offerings.
Acquisitions and Dispositions
On February 28, 2005, Pengrowth closed the acquisition of an additional 11.89 percent working
interest in Swan Hills increasing Pengrowths total working interest in the unit to 22.34 percent.
The purchase price was $87 million, after adjustments from the October 1, 2004 effective date to
the closing date.
On April 29, 2005, Pengrowth completed the acquisition of Crispin which held interests in oil and
natural gas assets mainly in Alberta. This represented Pengrowths first acquisition of a publicly
traded corporation and was funded through the issuance of Class A and Class B trust units valued at
approximately $88 million. Pengrowth also assumed debt of approximately $20 million as part of the
acquisition.
During the second half of 2005, Pengrowth received approximately $38 million of proceeds from the
sale of non-core oil and natural gas properties with associated production of approximately 600 boe
per day.
70
PENGROWTH ENERGY TRUST
On May 31, 2004, Pengrowth acquired oil and natural gas assets in Alberta and Saskatchewan from a
subsidiary of Murphy Oil Corporation for a purchase price of $550 million prior to adjustments.
On August 12, 2004, Pengrowth acquired an additional 34.35 percent interest in Kaybob Notikewin
Unit No. 1 for a purchase price of $20 million, bringing Pengrowths total working interest in this
unit to just below 99 percent.
Capital Expenditures
During 2005, Pengrowth spent $175.7 million on development and optimization activities. The
largest expenditures were in Judy Creek ($36.7 million), SOEP ($27.2 million), Princess ($11.1
million), Weyburn
($8.8 million), Prespatou ($7.5 million) and Swan Hills ($7.2 million). Pengrowth does not
typically participate in high risk exploration activities and in 2005 most of the capital spent on
development was directed towards increasing production, arresting production declines and improving
recovery through infill drilling.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($
millions) |
|
|
Three
months ended |
|
|
Twelve
months ended |
|
|
|
Dec. 31, 2005 |
|
|
Sep. 30, 2005 |
|
|
Dec. 31, 2004 |
|
|
Dec. 31, 2005 |
|
|
Dec. 31, 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical |
|
|
|
|
|
|
|
|
0.2 |
|
|
|
|
0.2 |
|
|
|
|
1.4 |
|
|
|
|
0.6 |
|
Drilling and completions |
|
|
|
41.1 |
|
|
|
|
29.8 |
|
|
|
|
36.2 |
|
|
|
|
130.3 |
|
|
|
|
111.5 |
|
Plant and facilities |
|
|
|
10.2 |
|
|
|
|
10.0 |
|
|
|
|
17.7 |
|
|
|
|
34.1 |
|
|
|
|
49.0 |
|
Land purchases |
|
|
|
8.8 |
|
|
|
|
0.8 |
|
|
|
|
|
|
|
|
|
9.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development capital |
|
|
|
60.1 |
|
|
|
|
40.8 |
|
|
|
|
54.1 |
|
|
|
|
175.7 |
|
|
|
|
161.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175.1 |
|
|
|
|
573.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
and acquisitions |
|
|
|
60.1 |
|
|
|
|
40.8 |
|
|
|
|
54.1 |
|
|
|
|
350.8 |
|
|
|
|
734.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pengrowths planned capital expenditures for maintenance and development opportunities at
existing properties are approximately $236 million for 2006 which is the largest capital program in
Pengrowths history. Approximately half of the 2006 spending will be on a 280 gross wells (132 net
wells) drilling program. The remainder of the budget will be spent on recompletions and
reactivations, development of coalbed methane resources, production enhancements and ongoing
maintenance. Pengrowths 2006 capital program targets the furtherance of Pengrowths short, medium
and long term objectives, reflecting Pengrowths focus on pursuing a balanced approach to the
development of its key assets. While the most significant portion of Pengrowths 2006 capital
program will involve the continued development and maintenance of existing production and
properties, a key element of the 2006 program will be further development of mid and longer term
plays or projects in coalbed methane, heavy oil and enhanced oil recovery.
Reserves
Pengrowth reported year end Proved plus Probable reserves of 219.4 mmboe compared to 218.6
mmboe at year end 2004. Further details of Pengrowths 2005 year end reserves are provided on pages
37 to 45 of the annual report.
71
2005 ANNUAL REPORT
Working Capital
Working capital declined by $33.7 million from a working capital deficiency of $78.5 million
in 2004 to a working capital deficiency of $112.2 million as at December 31, 2005. Most of the
working capital decline is attributable to an increase in bank indebtedness, accounts payable and
accrued liabilities, distributions payable to unitholders and the current portion of the note
payable, offset by an increase in accounts receivable as at December 31, 2005.
Pengrowth frequently operates with a working capital deficiency as a result of the fact that
distributions related to two production months of operating income are payable to unitholders at
the end of any month, but only one month of production is still receivable. For example, at the end
of December, distributions related to November and December production months were payable on
January 15 and February 15 respectively. Novembers production revenue, received on December 25, is
temporarily applied against Pengrowths revolving credit facility until the distribution payment on
January 15.
Financial
Resources and Liquidity
At year end 2005, Pengrowth had a long term debt to debt-plus-equity at book value ratio of
0.2 and maintained $370 million in committed credit facilities which were reduced by drawings of
$35 million and by $17 million in letters of credit outstanding at year end. In addition, Pengrowth
maintains a $35 million demand operating line of credit. Pengrowth remains well positioned to fund
its 2006 development program and to take advantage of acquisition opportunities as they arise. At
December 31, 2005, Pengrowth had $337 million available to draw from its credit facilities.
Long term debt at December 31, 2005 included fixed rate term debt denominated in U.S. dollars which
translated to Cdn $232.6 million. Due to the improvement in the Canadian to U.S. dollar exchange
rate, an unrealized gain of Cdn $57.6 million has been recorded since the U.S. dollar denominated
debt was issued in April of 2003. Long term debt at December 31, 2005 also included fixed rate term
debt of £50 million which translated to Cdn$100.5 million. Through a series of hedging
transactions, Pengrowth fixed the exchange rate in Canadian dollars for all future interest
payments and repayment at maturity.
Pengrowths long term debt increased by $22.7 million in fiscal 2005 to $368.1 million at December
31, 2005. At the end of 2005 Pengrowth also had a $20 million non-interest bearing note payable to
Emera related to the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The
terms of this note are provided in Note 7 to the financial statements.
During the year Pengrowth incurred $87 million of new debt to fund the acquisition of an additional
interest in Swan Hills and assumed $20 million of bank debt from the acquisition of Crispin.
Pengrowth was able to fund this new debt from its existing credit facilities.
Pengrowth anticipates funding its 2006 capital expenditures through a combination of undistributed
cash from operations, unused credit facilities and any proceeds from property dispositions.
72
PENGROWTH ENERGY TRUST
Financial Leverage and Coverage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve
months ended December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
Cash generated from operations to interest expense (times) |
|
|
|
29 |
|
|
|
|
13 |
|
Long term debt to cash generated from operations (times) |
|
|
|
0.6 |
|
|
|
|
0.9 |
|
Long term debt to debt plus book equity (%) |
|
|
|
20 |
|
|
|
|
19 |
|
|
|
|
|
|
|
|
Class A
and Class B Trust Unit Structure
Maintaining its status as a mutual fund trust under Income Tax Act (Canada) is of fundamental
importance to the Trust. Generally speaking, in addition to several other requirements, in order
for a trust such as Pengrowth to be a mutual fund trust under the Income Tax Act it must satisfy
one of two tests. The first test is a benefit test that requires that the trust must not be
established or maintained primarily for the benefit of non-residents of Canada (which is generally
interpreted to mean that the majority of unitholders must be residents of Canada) (the Benefit
Test). The second test is a property test that requires that, at all times after February 21,
1990, all or substantially all of the trusts property consist of property other than taxable
Canadian property (the Property Exception). Pengrowth is aware that many of its competitors have
significantly greater than 50 percent non-resident ownership and are relying on the Property
Exception to maintain their mutual fund trust status.
For reasons that may be unique to the Trust, it was not clear that the Trust could rely upon the
Property Exception, as a sale and leaseback transaction entered into with the Corporation in 1998
regarding certain facilities at Judy Creek may have resulted in the Trusts taxable Canadian
property exceeding the threshold required by the Property Exception. On November 26, 2004, the
Trust received a customary form of comfort letter from the Department of Finance (Canada) stating
that the Department of Finance will recommend to the Minister of Finance that an amendment be made
to the Property Exception that would clarify the Trusts ability to rely upon the Property
Exception.
As a result of this uncertainty, the Trust adopted the Class A and Class B trust unit structure,
which requires that the Class A trust units constitute not more than 49.75 percent of the
outstanding trust units of the Trust and that all of the Class B trust units be held by residents
of Canada, to ensure that the Trust would satisfy the Benefit Test. The Trust received an advance
tax ruling from the Canada Revenue Agency on July 26, 2004 and an amended ruling on December 1,
2004 that confirmed that the Trust would continue to be a mutual fund trust if the Class A trust
units constituted less than the ownership threshold of 49.75 percent by June 1, 2005 and the Trust
was a mutual fund trust prior to that date.
As at December 31, 2004, the Class A trust units represented 50.2 percent of the outstanding trust
units of the Trust. As a result of a public offering of Class B trust units in December of 2004,
the issuance of a majority of Class B trust units in connection with Pengrowths acquisition of
Crispin in 2005 and the issuance of Class B trust units in accordance with the Distribution
Reinvestment Program and other Pengrowth incentive plans, the ownership threshold of 49.75 percent
for the Class A trust units was achieved prior to June 1, 2005 in accordance with the advance
income tax ruling. On December 6, 2004, the Minister of Finance indicated that further discussions
and consultations concerning the appropriate tax treatment of non-residents owning resource
properties through mutual fund trusts would take place.
73
2005 ANNUAL REPORT
At present, Pengrowth is maintaining the Class A and Class B trust unit structure in compliance
with the advance income tax ruling. The Board of Directors considers it prudent at this time to
continue the Class A and Class B trust unit structure.
The Board of Directors may determine, based upon market circumstances as they exist at that time or
other factors, that it is in the best interests of all unitholders to: (a) remove the requirement
to comply with the ownership threshold that restricts the Class A trust units to 49.75 percent of
the outstanding trust units; (b) remove the residency restrictions pertaining to the holding of
Class B trust units; (c) permit a free conversion of Class B trust units to Class A trust units;
(d) permit the consolidation of the trust unit capital of the Trust; (e) allow a controlled
conversion of Class B trust units to Class A trust units over time to preserve an orderly market;
(f) maintain the Class A and Class B trust unit structure until market circumstances become more
favorable to both classes of unitholders; or (g) take such other action as the Board of Directors
may consider appropriate.
Commitments and Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Long term debt (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,450 |
|
|
|
193,639 |
|
|
|
368,089 |
|
Interest payments on
long term debt (2) |
|
|
17,298 |
|
|
|
17,298 |
|
|
|
17,298 |
|
|
|
17,298 |
|
|
|
11,564 |
|
|
|
34,546 |
|
|
|
115,302 |
|
Note payable |
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
Operating leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office rent |
|
|
2,030 |
|
|
|
2,070 |
|
|
|
3,096 |
|
|
|
3,055 |
|
|
|
3,036 |
|
|
|
21,529 |
|
|
|
34,816 |
|
Vehicle leases |
|
|
852 |
|
|
|
776 |
|
|
|
604 |
|
|
|
306 |
|
|
|
91 |
|
|
|
|
|
|
|
2,629 |
|
|
|
|
|
2,882 |
|
|
|
2,846 |
|
|
|
3,700 |
|
|
|
3,361 |
|
|
|
3,127 |
|
|
|
21,529 |
|
|
|
37,445 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation |
|
|
43,839 |
|
|
|
38,197 |
|
|
|
34,981 |
|
|
|
29,813 |
|
|
|
11,748 |
|
|
|
53,525 |
|
|
|
212,103 |
|
Capital expenditures |
|
|
33,323 |
|
|
|
7,098 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,715 |
|
CO2 purchases |
|
|
5,119 |
|
|
|
4,357 |
|
|
|
4,198 |
|
|
|
4,232 |
|
|
|
4,267 |
|
|
|
18,728 |
|
|
|
40,901 |
|
|
|
|
|
82,281 |
|
|
|
49,652 |
|
|
|
39,473 |
|
|
|
34,045 |
|
|
|
16,015 |
|
|
|
72,253 |
|
|
|
293,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remediation
trust fund payments |
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
11,250 |
|
|
|
12,500 |
|
|
|
|
|
122,711 |
|
|
|
70,046 |
|
|
|
60,721 |
|
|
|
54,954 |
|
|
|
205,406 |
|
|
|
333,217 |
|
|
|
847,055 |
|
|
|
|
|
(1) |
|
Foreign dollar denominated debt due as follows: $150 million U.S. in April 2010,
$50 million U.S. in April 2013 and £50 million in December 2015, translated at the Dec 31, 2005
exchange rate. |
|
(2) |
|
Interest payments on foreign denominated debt, calculated based on Dec 31, 2005
foreign exchange rate. |
74
PENGROWTH ENERGY TRUST
Trust
Unit Information
Trust Unit Trading after re-class(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
Low |
|
Close |
|
Volume (000s) |
|
Value ($ millions) |
|
TSX PGF.A ($ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
28.29 |
|
|
|
22.15 |
|
|
|
24.03 |
|
|
|
2,049 |
|
|
|
53.3 |
|
2nd quarter |
|
|
27.90 |
|
|
|
23.95 |
|
|
|
27.20 |
|
|
|
1,798 |
|
|
|
46.4 |
|
3rd quarter |
|
|
30.10 |
|
|
|
26.30 |
|
|
|
29.50 |
|
|
|
2,047 |
|
|
|
58.0 |
|
4th quarter |
|
|
29.80 |
|
|
|
23.64 |
|
|
|
27.41 |
|
|
|
1,324 |
|
|
|
35.2 |
|
Year |
|
|
30.10 |
|
|
|
22.15 |
|
|
|
27.41 |
|
|
|
7,218 |
|
|
|
192.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
24.19 |
|
|
|
19.10 |
|
|
|
22.67 |
|
|
|
1,672 |
|
|
|
35.5 |
|
4th quarter |
|
|
26.33 |
|
|
|
20.03 |
|
|
|
24.93 |
|
|
|
2,607 |
|
|
|
58.9 |
|
Year |
|
|
26.33 |
|
|
|
19.10 |
|
|
|
24.93 |
|
|
|
4,279 |
|
|
|
94.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TSX PGF.B ($ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
19.90 |
|
|
|
16.10 |
|
|
|
17.05 |
|
|
|
29,219 |
|
|
|
543.7 |
|
2nd quarter |
|
|
19.01 |
|
|
|
16.37 |
|
|
|
18.40 |
|
|
|
19,370 |
|
|
|
342.5 |
|
3rd quarter |
|
|
21.26 |
|
|
|
18.25 |
|
|
|
20.58 |
|
|
|
22,738 |
|
|
|
441.0 |
|
4th quarter |
|
|
23.38 |
|
|
|
17.27 |
|
|
|
22.65 |
|
|
|
19,747 |
|
|
|
411.0 |
|
Year |
|
|
23.38 |
|
|
|
16.10 |
|
|
|
22.65 |
|
|
|
91,074 |
|
|
|
1,738.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
20.00 |
|
|
|
18.03 |
|
|
|
18.87 |
|
|
|
5,588 |
|
|
|
105.6 |
|
4th quarter |
|
|
20.04 |
|
|
|
17.51 |
|
|
|
18.50 |
|
|
|
16,007 |
|
|
|
301.8 |
|
Year |
|
|
20.04 |
|
|
|
17.51 |
|
|
|
18.50 |
|
|
|
21,595 |
|
|
|
407.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYSE PGH ($ U.S.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
22.94 |
|
|
|
18.11 |
|
|
|
20.00 |
|
|
|
24,621 |
|
|
|
515.1 |
|
2nd quarter |
|
|
22.74 |
|
|
|
19.05 |
|
|
|
22.25 |
|
|
|
16,153 |
|
|
|
335.0 |
|
3rd quarter |
|
|
25.75 |
|
|
|
21.55 |
|
|
|
25.42 |
|
|
|
14,502 |
|
|
|
340.3 |
|
4th quarter |
|
|
25.56 |
|
|
|
20.00 |
|
|
|
23.53 |
|
|
|
17,808 |
|
|
|
399.7 |
|
Year |
|
|
25.75 |
|
|
|
18.11 |
|
|
|
23.53 |
|
|
|
73,084 |
|
|
|
1,590.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
18.94 |
|
|
|
14.40 |
|
|
|
17.93 |
|
|
|
21,200 |
|
|
|
350.4 |
|
4th quarter |
|
|
21.24 |
|
|
|
15.85 |
|
|
|
20.82 |
|
|
|
31,174 |
|
|
|
574.7 |
|
Year |
|
|
21.24 |
|
|
|
14.40 |
|
|
|
20.82 |
|
|
|
52,374 |
|
|
|
925.1 |
|
|
|
|
|
(1) |
|
July 27, 2004, trust units were re-classified as Class A or Class B trust units.
Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock
Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. |
75
2005
ANNUAL REPORT
Trust
Unit Trading before re-class(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
Low |
|
Close |
Volume (000s) Value ($ millions) |
|
TSX PGF.UN ( $ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
21.25 |
|
|
|
15.55 |
|
|
|
17.98 |
|
|
|
30,620 |
|
|
|
567.8 |
|
2nd quarter |
|
|
19.15 |
|
|
|
16.15 |
|
|
|
18.67 |
|
|
|
18,145 |
|
|
|
328.5 |
|
3rd quarter |
|
|
19.75 |
|
|
|
18.52 |
|
|
|
19.42 |
|
|
|
3,554 |
|
|
|
68.5 |
|
4th quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
21.25 |
|
|
|
15.55 |
|
|
|
19.42 |
|
|
|
52,319 |
|
|
|
964.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYSE PGH ($ U.S.)
|
|
|
16.60 |
|
|
|
12.10 |
|
|
|
13.70 |
|
|
|
36,899 |
|
|
|
525.6 |
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
14.24 |
|
|
|
11.62 |
|
|
|
13.98 |
|
|
|
22,194 |
|
|
|
295.9 |
|
3rd quarter |
|
|
14.95 |
|
|
|
13.84 |
|
|
|
14.64 |
|
|
|
5,797 |
|
|
|
84.5 |
|
4th quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
14.95 |
|
|
|
11.62 |
|
|
|
14.64 |
|
|
|
64,890 |
|
|
|
906.0 |
|
|
|
|
|
(1) |
|
July 27, 2004, trust units were re-classified as Class A or Class B trust units.
Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock
Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. |
Pengrowth had 159,864,083 trust units outstanding at December 31, 2005, compared to
152,972,555 trust units at December 31, 2004. The weighted average number of trust units during the
year was 157,127,181 (2004 133,935,485).
On April 29, 2005, Pengrowth issued 4.2 million trust units to complete the Crispin acquisition.
(see Note 4 to the financial statements for further detail).
76
PENGROWTH ENERGY TRUST
Summary of Quarterly Results
The following table is a summary of quarterly results for 2005 and 2004. As this table
illustrates, production and distributable cash were impacted positively by the Murphy acquisition
in the second quarter of 2004.
This table also shows the relatively high commodity prices sustained throughout 2004 and 2005,
which have had a positive impact on net income and distributable cash.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1 |
|
Q2 |
|
Q3 |
|
Q4 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales ($000s) |
|
|
239,913 |
|
|
|
253,189 |
|
|
|
304,484 |
|
|
|
353,923 |
|
Net income ($000s) |
|
|
56,314 |
|
|
|
53,106 |
|
|
|
100,243 |
|
|
|
116,663 |
|
Net income per trust unit ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Net income per trust unit diluted ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Distributable cash ($000s) |
|
|
127,804 |
|
|
|
134,047 |
|
|
|
162,009 |
|
|
|
195,879 |
|
Actual distributions paid or declared per trust unit ($) |
|
|
0.69 |
|
|
|
0.69 |
|
|
|
0.69 |
|
|
|
0.75 |
|
Daily production (boe) |
|
|
59,082 |
|
|
|
57,988 |
|
|
|
58,894 |
|
|
|
61,442 |
|
Total production (mboe) |
|
|
5,317 |
|
|
|
5,277 |
|
|
|
5,418 |
|
|
|
5,653 |
|
Average realized price ($ per boe) |
|
|
44.97 |
|
|
|
47.79 |
|
|
|
56.07 |
|
|
|
62.55 |
|
Operating netback ($ per boe) |
|
|
27.70 |
|
|
|
29.26 |
|
|
|
33.94 |
|
|
|
38.81 |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales ($000s) (1) |
|
|
168,771 |
|
|
|
197,284 |
|
|
|
226,514 |
|
|
|
223,183 |
|
Net income ($000s) |
|
|
38,652 |
|
|
|
32,684 |
|
|
|
51,271 |
|
|
|
31,138 |
|
Net income per trust unit ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Net income per trust unit diluted ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Distributable cash ($000s) (1) |
|
|
92,895 |
|
|
|
99,021 |
|
|
|
104,304 |
|
|
|
104,958 |
|
Actual distributions paid or declared per trust unit ($) |
|
|
0.63 |
|
|
|
0.64 |
|
|
|
0.67 |
|
|
|
0.69 |
|
Daily production (boe) |
|
|
45,668 |
|
|
|
51,451 |
|
|
|
60,151 |
|
|
|
57,425 |
|
Total production (mboe) |
|
|
4,156 |
|
|
|
4,682 |
|
|
|
5,534 |
|
|
|
5,283 |
|
Average realized price ($ per boe) (1) |
|
|
40.37 |
|
|
|
41.83 |
|
|
|
40.90 |
|
|
|
42.08 |
|
Operating netback ($ per boe) |
|
|
25.71 |
|
|
|
25.71 |
|
|
|
22.77 |
|
|
|
24.31 |
|
|
Selected Annual Information Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months ended December 31 |
($ thousands) |
|
2005 |
|
2004 |
|
2003 |
|
Oil and gas sales (1) |
|
|
1,151,510 |
|
|
|
815,751 |
|
|
|
702,732 |
|
Net income |
|
|
326,326 |
|
|
|
153,745 |
|
|
|
189,297 |
|
Net income per trust unit |
|
|
2.08 |
|
|
|
1.15 |
|
|
|
1.63 |
|
Distributable cash (1) |
|
|
619,739 |
|
|
|
401,178 |
|
|
|
345,911 |
|
Actual distributions paid or declared per trust unit |
|
|
2.82 |
|
|
|
2.63 |
|
|
|
2.68 |
|
Total assets |
|
|
2,391,432 |
|
|
|
2,276,534 |
|
|
|
1,673,718 |
|
Long term financial liabilities (2) |
|
|
381,026 |
|
|
|
383,616 |
|
|
|
294,300 |
|
Unitholders equity |
|
|
1,475,996 |
|
|
|
1,462,211 |
|
|
|
1,159,433 |
|
Number of units outstanding at year end (thousands) |
|
|
159,864 |
|
|
|
152,973 |
|
|
|
123,874 |
|
|
|
|
|
(1) |
|
Prior years restated to conform to
presentation adopted in the current year |
|
(2) |
|
Long term debt plus long term portion of note
payable and contract liabilities |
77
2005 ANNUAL REPORT
Business Risks
The amount of distributable cash available to unitholders and the value of Pengrowth Energy
Trust units are subject to numerous risk factors. As the trust units allow investors to participate
in the net cash flow from Pengrowths portfolio of producing oil and natural gas properties, the
principal risk factors that are associated with the oil and gas business include, but are not
limited to, the following influences:
|
|
The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due to many
factors including local and global market supply and demand, weather patterns, pipeline
transportation, and political stability. |
|
|
|
The marketability of our production depends in part upon the availability, proximity and
capacity of gathering systems, pipelines and processing facilities. Operational or economic
factors may result in the inability to deliver our products to market. |
|
|
|
Geological and operational risks affect the quantity and quality of reserves and the costs of
recovering those reserves. Our actual results will vary from our reserve estimates, and those
variations could be material. |
|
|
|
Government royalties, income taxes, commodity taxes, and other taxes, levies and fees have a
significant economic impact on Pengrowths financial results. Changes to federal and
provincial legislation governing such royalties, taxes and fees could have a material impact
on Pengrowths financial results and the value of Pengrowth trust units. |
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Environmental laws and regulatory initiatives impact Pengrowth financially and operationally.
We may incur substantial capital and operating expenses to comply with increasingly complex
laws and regulations covering the protection of the environment and human health and safety.
In particular, we may be required to incur significant costs to comply with the 1997 Kyoto
Protocol to the United Nations Framework Convention on Climate Change. |
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Pengrowths oil and gas reserves will be depleted over time and our level of distributable
cash and the value of our trust units could be reduced if reserves and production are not
replaced. The ability to replace production depends on Pengrowths success in developing
existing reserves, acquiring new reserves and financing this development and acquisition
activity within the context of the capital markets. |
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Increased competition for properties will drive the cost of acquisition up and expected
returns from the properties down. |
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A significant portion of our properties are operated by third parties. If these operators
fail to perform their duties properly, or become insolvent, we may experience interruptions in
production and revenues from these properties or incur additional liabilities and expenses as
a result of the default of these third party operators. |
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Increased activity within the oil and gas sector can increase the cost of goods and services
and make it more difficult to hire and retain professional staff. |
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Changing interest rates influence borrowing costs and the availability of capital. |
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Investors interest in the oil and gas sector may change over time which would affect the
availability of capital and the value of Pengrowth trust units. |
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PENGROWTH ENERGY TRUST
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The value of Class A trust units and Class B trust units, relative to one another, may be
influenced by the different markets in which the trust units trade, the restrictions in
entitlement of the Class B trust units to Canadian residents and the limitation in the number
of Class A trust units beneath an ownership threshold of 49.75 percent of all trust units
outstanding. |
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Inflation may result in escalating costs which could impact unitholder distributions and the
value of Pengrowth trust units. |
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Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and
capital costs. |
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The value of Pengrowth trust units is impacted directly by the related tax treatment of the
trust units and the trust unit distributions, and indirectly by the tax treatment of
alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely
affect the value of our trust units. |
Pengrowth mitigates some of these risks by:
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Fixing the price on a portion of its future crude oil and natural gas production. |
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Fixing the Canadian / U.S. exchange rate through financial hedging contracts or by fixing
commodity prices in Canadian dollars. |
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Offering competitive incentive-based compensation packages to attract and retain highly
qualified and motivated professional staff. |
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Adhering to strict investment criteria for acquisitions. |
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Acquiring mature production with long life reserves and proven production. |
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Performing extensive geological, geophysical, engineering and environmental analysis before
committing to capital development projects. |
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Geographically diversifying its portfolio. |
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Controlling costs to maximize profitability. |
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Developing and adhering to policies and practices that protect the environment and meet or
exceed the regulations imposed by the government. |
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Developing and adhering to safety policies and practices that meet or exceed regulatory standards. |
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Ensuring strong third party operators for non-operated properties. |
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Carrying insurance to cover physical losses and business interruption. |
These factors should not be considered to be exhaustive. Additional risks are outlined in the
Annual Information Form (AIF) of the Trust available on SEDAR at www.sedar.com on or before March
31, 2006.
Subsequent Event
On January 12, 2006, Pengrowth announced certain transactions with Monterey under which
Pengrowth has sold oil and gas properties for $22 million of cash and eight million shares in
Monterey. As at February 27, 2006 Pengrowth holds approximately 34 percent of the common shares of
Monterey.
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2005 ANNUAL REPORT
Outlook
Pengrowth will seek to provide attractive long term returns for unitholders. Our business
objectives include:
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Operating our properties in a safe and prudent manner in order to protect our employees, the
public, the environment and our investment; |
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Maintaining a balanced portfolio of oil and gas properties in our key focus areas; |
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Growing production and reserves through accretive acquisitions and low risk development drilling; |
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Increasing our undeveloped land position; |
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Continuing to optimize costs and maximize netbacks; |
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The selective disposition of oil and gas properties that do not meet our return objectives; |
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Continuing to maintain a stable distribution policy while withholding a portion of
distributable cash to fund future capital programs. |
At this time, Pengrowth is forecasting average 2006 production of 54,000 to 56,000 boe per day from
our existing properties. This estimate incorporates anticipated production additions from our 2006
development program, offset by the impact of divestitures of approximately 1,300 boe per day and
expected production declines from normal operations. The above estimate excludes the potential
impact of any future acquisitions or divestitures.
Total operating expenses for 2006 are expected to increase to approximately $220 million. This
increase is due to the addition of a full-year of operating expenses associated with Pengrowths
increased working interest in Swan Hills and the acquisition of Crispin. Assuming Pengrowths
average production for 2006 as forecast above, Pengrowth currently estimates 2006 per boe operating
expenses of approximately $11.00 per boe.
Budgeted capital expenditures for 2006 total approximately $236 million. Approximately half of the
budgeted 2006 expenditures is for a 280 gross wells (132 net wells) drilling program, 27 percent
are for facilities and maintenance, nine percent are for land and seismic acquisitions, and eight
percent for recompletions, workovers,
CO2 pilot and other. Pengrowths 2006
capital program targets the furtherance of Pengrowths short, medium and long term objectives,
reflecting Pengrowths focus on pursuing a balanced approach to the development of its key assets.
While the most significant portion of Pengrowths 2006 capital program will involve the continued
development and maintenance of existing production and properties, a key element of the 2006
program will be further development of mid and longer term plays or projects in coalbed methane,
heavy oil and enhanced recovery.
Disclosure Controls and Procedures
As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is
required to comply with Multilateral Instrument 52-109 Certification of Disclosure in Issuers
Annual and Interim Filings, as well as the Sarbanes Oxley Act (SOX) enacted in the United States.
Both the Canadian regulations and the U.S. certification rules include similar requirements where
both the Chief Executive Officer and the Chief Financial Officer must assess and certify as to the
effectiveness of the internal controls over the disclosure of annual filings, interim filings,
reports and other releases of material information.
The Chief Executive Officer, James Kinnear, and the Chief Financial Officer, Christopher Webster,
evaluated the effectiveness of Pengrowths disclosure controls and procedures for the period ending
December 31st, 2005. This evaluation considered the functions performed by its Disclosure
Committee, the review and oversight of all executive officers and the board, as well as the process
and systems in place for filing regulatory and public information. Pengrowths established review
process and disclosure controls are designed to ensure that all required information, reports and
filings required under provincial securities legislation and United States securities laws are
properly submitted and recorded in a timely fashion. Pengrowths disclosure controls and procedures
were certified as being effective for that period on Form 52-109F1 but Pengrowth omitted reference
to this evaluation in its Managements Discussion and Analysis for the period filed under Canadian
securities laws. Pengrowth did disclose this evaluation in its filings for the period under U.S.
securities laws. Pengrowth continues to believe that the processes, practices and administration
procedures it has in place provide effective disclosure controls.
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PENGROWTH ENERGY TRUST